SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC  20549


                                    FORM 10-K


[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934 FOR THE FISCAL YEAR ENDED JUNE 30, 2004.

                                       or

[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD FROM ________ TO ________.

                       Commission file number 333-29001-01


                          ENERGY CORPORATION OF AMERICA
             (Exact name of registrant as specified in its charter)


                           WEST VIRGINIA   84-1235822
         (State or other jurisdiction of incorporation or organization)
                      (IRS Employer Identification Number)

                      4643 SOUTH ULSTER STREET, SUITE 1100
                             DENVER, COLORADO  80237
              (Address of principal executive offices and zip code)

                                 (303) 694-2667
              (Registrant's telephone number, including area code)



    Securities registered pursuant to Section 12(b) of the Act:          None

    Securities registered pursuant to Section 12(g) of the Act:          None


Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding  12  months  (or  for such shorter period that the registrant was
required  to  file  such  reports),  and  (2)  has  been  subject to such filing
requirements  for  the  past  90  days.     Yes  [X]     No  [_]


<PAGE>
Indicate  by  check mark if disclosure of delinquent filers pursuant to Item 405
of the Regulation S-K is not contained herein, and will not be contained, to the
best  of  registrant's  knowledge, in definitive proxy or information statements
incorporated by reference in part III of this Form 10-K or any amendment to this
Form  10-K.                                                         [X]

Indicate  by  check  mark  whether  the  registrant  is an accelerated filer (as
defined  in  Rule  12b-2  of  the  Act).
Yes  [_]  No  [X]


The  aggregate  number  of  shares  and  market  value  of  common stock held by
non-affiliates  of  the registrant at September 23, 2004 was 38,350 shares.  The
market  value  held  by  non-affiliates  is  unavailable.


The  number  of  shares  of  the  registrant's common stock, par value $1.00 per
share,  outstanding  at  September  23,  2004  was  602,426  shares.



                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE


                                        2
<PAGE>
<TABLE>
<CAPTION>
                                   ENERGY CORPORATION OF AMERICA

                                         TABLE OF CONTENTS


                                                                                              Page
Part I
<S>            <C>                                                                          <C>
     Item 1.   Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    4
     Item 2.   Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    7
     Item 3.   Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   10
     Item 4.   Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . .   11
Part II
     Item 5.   Market for the Registrant's Common Stock and Related Stockholder Matters . .   11
     Item 6.   Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . .   11
     Item 7.   Management's Discussion and Analysis of Results of Operations
               and Financial Condition. . . . . . . . . . . . . . . . . . . . . . . . . . .   11
     Item 7A.  Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . .   24
     Item 8.   Consolidated Financial Statements and Supplementary Data
                 Report of Independent Registered Public Accounting Firm. . . . . . . . . .   26
                 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   27
                 Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . .   29
                 Statements of Stockholders Equity. . . . . . . . . . . . . . . . . . . . .   30
                 Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . .   31
                 Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . .   32
                 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . .   33
                 Supplemental Information on Oil and Gas Producing Activities (Unaudited) .   52
     Item 9.   Changes In and Disagreements With Accountants on Accounting
               and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . .   57
     Item 9A.  Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . .   57
Part III
     Item 10.  Directors and Officers of Registrant . . . . . . . . . . . . . . . . . . . .   57
     Item 11.  Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . .   61
     Item 12.  Security Ownership of Certain Beneficial Owners and Management . . . . . . .   62
     Item 13.  Certain Relationships and Related Transactions . . . . . . . . . . . . . . .   65
     Item 14.  Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . .   66
Part IV
     Item 15.  Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . .   68
Part V
     Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   72
</TABLE>


                                        3
<PAGE>
                                     PART I
                                     ------

                               ITEM 1.    BUSINESS
                               -------------------

GENERAL
-------

     Energy  Corporation  of  America (the "Company") is a privately held energy
company  engaged  in  the  exploration,  development,  production, gathering and
aggregation  of natural gas and oil, primarily in the Appalachian Basin and Gulf
Coast  regions  in  the  United  States  and  New Zealand.  The Company conducts
business primarily through its principal wholly owned subsidiaries and is one of
the  largest oil and gas operators in the Appalachian Basin.  As used herein the
"Company"  refers  to  the  Company  alone  or  together with one or more of its
subsidiaries.

     The  Company was formed in June 1993 through an exchange of shares with the
common  stockholders  of  Eastern  American  Energy  Corporation  ("Eastern
American").

     As  of  June  30,  2004, the Company had approximately 229 full-time and 27
part-time  employees.  None  of  the  employees  were  covered  by  a collective
bargaining  agreement.  Management  believes  that  its  relationship  with  its
employees  is  good.

     The  principal  offices  of  the  Company  are located at 4643 South Ulster
Street,  Suite  1100,  Denver, Colorado 80237, and the telephone number is (303)
694-2667.

     Definitions - All defined terms under Rule 4-10 (a) of Regulation S-X shall
have their statutorily prescribed meanings when used in this report.  Quantities
of  natural  gas  are  expressed  in this report in terms of thousand cubic feet
(Mcf),  million cubic feet (Mmcf), billion cubic feet (Bcf), dekatherm (Dth), or
thousand dekatherms (Mdth).  A dekatherm is equal to one million British Thermal
Units  (Btu).  A  Btu is the amount of heat required to raise the temperature of
one  pound of water one degree Fahrenheit.  With respect to information relating
to  the  Company's working interest in wells or acreage, "net" oil and gas wells
or  acreage is determined by multiplying gross wells or acreage by the Company's
working  interest  therein.  Oil  is  quantified  in  terms  of  barrels (Bbls),
thousand  barrels  (Mbbls)  or  million  barrels  (Mmbbls).  Oil  is compared to
natural  gas  in  terms  of thousand cubic feet equivalent (Mcfe), million cubic
feet  equivalent (Mmcfe) or billion cubic feet equivalent (Bcfe).  One barrel of
oil  is assumed to have the energy equivalent of six Mcf of natural gas.  Unless
otherwise  specified,  all  references  to  wells  and  acres  are  gross.


BUSINESS  ACTIVITY
------------------

SEGMENT  INFORMATION
--------------------

     The  Company's businesses constitute two operating segments (i) gas and oil
exploration  and  production  and  (ii)  gas  aggregation  and  pipelines.  For
financial  information  on  these  segments,  see  Note  16  to the Consolidated
Financial  Statements.


                                        4
<PAGE>
GAS AND OIL EXPLORATION AND PRODUCTION
--------------------------------------

     OPERATIONS AND SIGNIFICANT DEVELOPMENTS

     The  Company's proved net gas and oil reserves are estimated as of June 30,
2004  at  215,475 Mmcf and 1,280 Mbbls, respectively.  For the fiscal year ended
June  30,  2004,  the  Company's  net gas production was 10,718 Mmcf and net oil
production  was  107  Mbbls,  for  a  total  of  11,360  net  Mmcfe.

     DEVELOPMENT ACTIVITY

     The  Company,  in fiscal year 2004, drilled 27 productive gross wells (17.6
net), and recompleted 2 wells, adding 5,234 gross Mcf of gas production per day.

     EXPLORATORY ACTIVITY

     Exploration  wells  and  activity  are  summarized  under  their respective
project  areas.

          1. Newburg/Silurian, Trenton/Black River -- West Virginia. The Company
     drilled  one  successful well, two dry holes and one well that is currently
     being  tested  and  appears  to  be productive. Current production from the
     Trenton/Black  River  discovery  is approximately 700 gross Mcf per day and
     140  net  Mcf  per  day.  The  Company  plans  to continue to pursue select
     extension  and  exploration  opportunities  in  both  trends.

          2.  Texas.  The  Company drilled four exploratory wells with a success
     rate  of  50%.  The  principal  producing formation is the Wilcox at depths
     ranging  to  16,000  feet. The Company is working on a development drilling
     plan  to  capitalize  on  its  exploration  success.

          3.  New  Zealand.  The Company drilled an unsuccessful well in the Mt.
     Messenger  formation  in the Taranaki region. The Company continues with an
     active  drilling  program  in  New  Zealand.

          4.  Rocky Mountains. The Company drilled four unsuccessful exploration
     wells  in  the  northern  Powder  River  Basin.

COMPETITION
-----------

     The  Company  encounters  substantial  competition in acquiring properties,
aggregating oil and gas, securing drilling equipment and personnel and operating
its  properties.  The  competitors in acquisitions, development, exploration and
production  include  major  oil  companies,  numerous  independent  oil  and gas
companies,  gas  marketers,  individual  proprietors  and  others.

     Natural  gas  competes  with  other forms of energy available to customers,
primarily  based on price.  These alternate forms of energy include electricity,
coal  and  fuel  oils.  Changes  in  the availability or price of natural gas or
other  forms  of  energy,  as  well  as  business  conditions,  conservation,
legislation, regulations and the ability to convert to alternate fuels and other
forms  of  energy  may  affect  the  demand  for  natural  gas.

REGULATIONS  AFFECTING  OPERATIONS
----------------------------------

     The  Company's  operations are affected by extensive regulation pursuant to
various  federal,  state  and  local  laws  and  regulations  relating  to  the
exploration  for  and  development,  production,  gathering,  aggregation,
transportation  and  storage  of  oil  and  gas.  These regulations, among other
things,  can  affect


                                        5
<PAGE>
the  rate  of  oil  and gas production.  The Company's operations are subject to
numerous  laws and regulations governing plugging and abandonment, the discharge
of  materials  into  the  environment  or  otherwise  relating  to environmental
protection.  These  laws  and  regulations  require  the acquisition of a permit
before  drilling commences, restricts the types, quantities and concentration of
various  substances that can be released into the environment in connection with
drilling activities on certain lands lying within wilderness, wetlands and other
protected  areas,  and  impose substantial liabilities for pollution which might
result  from  the  Company's  operations.  The  Company  believes  it  is within
substantial  compliance  with  regulations  affecting  the  Company.

GAS  AGGREGATION  AND  PIPELINES
---------------------------------

     The  Company,  primarily  through  its  wholly  owned  subsidiary  Eastern
Marketing  Corporation ("Eastern Marketing"), aggregates natural gas through the
purchase  of  production  from  properties in the Appalachian Basin in which the
Company  has  an  interest,  the purchase of gas delivered through the Company's
gathering pipelines located in the Appalachian Basin, and the purchase of gas in
the  spot  market.  The  Company  sells gas to local gas distribution companies,
industrial  end users located in the Northeast, other gas marketing entities and
into  the  spot  market  for  gas  delivered  into  interstate  pipelines.

     The Company owns and operates approximately 2,280 miles of gathering lines
and  intrastate  pipelines  that are used in connection with its gas aggregation
activities.  The  Company  finalized the purchase of an additional 100-mile long
natural  gas  gathering  system  ("System  8000") from Columbia Gas Transmission
during  the  first  quarter  of  fiscal  year  2005.  System  8000 is located in
northeastern  West  Virginia  and is situate among one of the Company's existing
operating  areas.

     During  the  fiscal year ended June 30, 2004, Eastern Marketing aggregated
and  sold  an  average  of  40.4 Mmcf of gas per day, of which 38.9 Mmcf per day
represented  sales  of  gas  produced  from wells operated by the Company.  This
represents  a  2%  decrease in the overall volumes compared to fiscal year 2003,
during  which  Eastern  Marketing aggregated and sold an average of 41.2 Mmcf of
gas  per  day.

GAS  SALES  AND  PURCHASE  CONTRACTS
-------------------------------------

     The  Company  has  satisfied its obligations under all gas sales contracts
(14.7  Bcf  in  fiscal year 2004) through gas production attributable to its own
interests in oil and gas properties and through production attributable to third
party  interests  in  the same oil and gas properties (14.2 Bcf in fiscal 2004),
and  from  natural  gas  purchased  by  the  Company pursuant to its aggregation
activities  from  third  parties  (0.5  Bcf  in  fiscal  2004).

     On  November  30,  2001,  the  Company  entered  into  a natural gas sales
contract  with  Mountaineer  Gas  Company, doing business as Allegheny Power, to
deliver  5,500  Dth  per  day.  Under the pricing terms, the minimum price to be
received  by  the  Company  is  $2.75 per Dth plus the Columbia Gas Transmission
("TCO")  Appalachia  Basis  and the maximum to be received is $4.85 per Dth plus
the  TCO  Appalachia Basis.  The pricing terms also allow the Company to fix the
price  on  50%  of  the volumes.  The Company has locked the price on 50% of the
volumes  from  July 1, 2003 through October 31, 2004 at a weighted average price
of  $4.85 per Dth plus the TCO Appalachia Basis.  The contract began on December
1,  2001  and  continues  through  October  31,  2004.

     The  Company  entered  into a gas sales contract with AFG Industries, Inc.
("AFG")  for  the sale of up to 4,000 MMBtu per day from January 1, 2004 through
December  31,  2004.   AFG  is  a  "Float  Glass"  plant adjacent to an existing
Company  pipeline.  The  sales  contract price is based off the NYMEX settlement
price for Natural Gas Henry Hub Futures Contracts each month plus an Appalachian
Basis  component.


                                        6
<PAGE>
     In  March  1993, the Company entered into a gas purchase contract with the
Eastern  American  Natural  Gas  Trust (the "Royalty Trust") to purchase all gas
production  attributable to the Royalty Trust until its termination in May 2013.
The  purchase  contract  price is based off of the average of certain Hentry Hub
Gas  Futures  Contracts  related  to the month of production plus an Appalachian
Basis  component.

REGULATIONS  AFFECTING  MARKETING  AND  TRANSPORTATION
-------------------------------------------------------

     As a purchaser of  natural gas, the Company depends on the transportation,
gathering  and  storage  services  offered  by various interstate and intrastate
pipeline  companies for the delivery and sale of its own gas supplies as well as
those  it  processes  and/or  markets  for  others.  Both  the  performance  of
transportation  and  storage  services  by  interstate  pipelines  and the rates
charged  for such services are subject to the jurisdiction of the Federal Energy
Regulatory  Commission.  In  addition,  the  performance  of  transportation,
gathering and storage services by intrastate pipelines and the rates charged for
such  services  are  subject  to the jurisdiction of state regulatory agencies.


                             ITEM 2.     PROPERTIES
                             -------     -----------

OIL  AND  GAS  RESERVES
-----------------------

     The following information relating to estimated reserve quantities, reserve
values  and discounted future net revenues is derived from, and qualified in its
entirety  by reference to, the more complete reserve and revenue information and
assumptions  included  in  the Company's Supplemental Oil and Gas Disclosures at
Item  8.  The Company's estimates of proved reserve quantities of its properties
have  been  subject  to  review  by  Ryder  Scott Company, independent petroleum
engineers.  There  are  numerous uncertainties inherent in estimating quantities
of  proved  reserves  and  projecting  future  rates of production and timing of
development  expenditures.  The  following  reserve  information  represents
estimates  only  and  should  not  be  construed as being exact.  Future reserve
values  are based on year-end prices except in those instances where the sale of
gas  and  oil  is covered by contract terms.  Operating costs, production and ad
valorem  taxes  and  future development costs are based on current costs with no
escalations.

     The  following  table  sets forth the Company's estimated proved and proved
developed  reserves  and  the  related estimated future value, as of June 30:


                                        7
<PAGE>
<TABLE>
<CAPTION>
                                                   2004       2003      2002
                                                ----------  --------  --------
<S>                                             <C>         <C>       <C>
Net proved:
    Gas (Mmcf)                                     215,475   190,796   183,345
    Oil (Mbbls)                                      1,280     2,366     2,951
    Total (Mmcfe)                                  223,155   204,992   201,051

Net proved developed:
    Gas (Mmcf)                                     170,131   161,796   160,224
    Oil (Mbbls)                                        626     1,064     1,135
    Total (Mmcfe)                                  173,887   168,180   167,034

Estimated future net cash flows
  before income taxes (in thousands)            $1,074,207  $916,885  $471,927
Present value of estimated future net cash
  flows before income taxes (in thousands) (1)  $  435,387  $382,094  $200,087
_______________
</TABLE>
(1)  Discounted  using  an  annual  discount  rate  of  10%.

     The  following table sets forth the Company's estimated proved reserves and
the  related  estimated  present  value  by  region,  as  of  June  30,  2004:

<TABLE>
<CAPTION>
                       Present Value
                   --------------------                         Natural Gas
                      Amount               Oil    Natural Gas    Equivalent
     Region        (thousands)     %     (Mbbls)     (Mmcf)       (Mmcfe)
-----------------  ------------  ------  -------  ------------  ------------
<S>                <C>           <C>     <C>      <C>           <C>

Appalachian Basin  $    364,258   83.7%      422       178,767       181,299
Western                  53,958   12.4%      362        30,881        33,053
New Zealand              17,171    3.9%      496         5,827         8,803
                   ------------  ------  -------  ------------  ------------
Total              $    435,387  100.0%    1,280       215,475       223,155
                   ============  ======  =======  ============  ============
</TABLE>

PRODUCING  WELLS
----------------

     The  following  table sets forth certain information relating to productive
wells  at  June 30, 2004.  Wells are classified as oil or gas according to their
predominant  production  stream.

<TABLE>
<CAPTION>
                        Gross Wells                Net Wells
                   =======================  ======================
     Region         Oil     Gas     Total   Oil     Gas     Total
-----------------  -----  -------  -------  ----  -------  -------
<S>                <C>    <C>      <C>      <C>   <C>      <C>

Appalachian Basin   21.0  5,299.0  5,320.0  13.0  3,347.0  3,360.0
Western              7.0     15.0     22.0   2.6      4.4      7.0
New Zealand            -      4.0      4.0     -      4.0      4.0
                   -----  -------  -------  ----  -------  -------
Total               28.0  5,318.0  5,346.0  15.6  3,355.4  3,371.0
                   =====  =======  =======  ====  =======  =======
</TABLE>


                                        8
<PAGE>
ACREAGE
-------

     The  following table sets forth the developed and undeveloped gross and net
acreage  held  at  June  30,  2004:

<TABLE>
<CAPTION>
                    Developed Acreage      Undeveloped Acreage
                   ====================  ========================
     Region          Gross       Net        Gross         Net
-----------------  ---------  ---------  -----------  -----------
<S>                <C>        <C>        <C>          <C>
Appalachian Basin  405,030.0  312,105.4    115,940.9     98,410.9
Western              2,448.0    1,244.3     57,262.2     34,523.5
New Zealand            740.0      736.3  2,545,848.3  1,795,502.2
                   ---------  ---------  -----------  -----------
Total              408,218.0  314,086.0  2,719,051.4  1,928,436.6
                   =========  =========  ===========  ===========
</TABLE>


PRODUCTION
----------

     The  following  table  sets  forth  certain net production data and average
wellhead  sales  prices  attributable  to the Company's properties for the years
ended  June  30:

<TABLE>
<CAPTION>
                                                       2004     2003     2002
                                                      -------  -------  -------
<S>                                                   <C>      <C>      <C>
Production Data:
     Oil (Mbbls)                                          107      104      124
     Natural gas (Mmcf)                                10,718    9,756    9,941
     Natural gas equivalent (Mmcfe)                    11,360   10,380   10,685
Average Sales Price (before the effect of hedging):
     Oil per Bbl                                      $ 29.94  $ 25.97  $ 21.11
     Natural gas per Mcf                              $  5.49  $  5.13  $  2.86
</TABLE>

DRILLING  ACTIVITIES
--------------------

     The Company's gas and oil exploratory and developmental drilling activities
are  as follows for the years ended June 30.  The number of wells drilled refers
to  the number of wells commenced at any time during the respective fiscal year.
A  well  is  considered productive if it justifies the installation of permanent
equipment  for  the  production  of  gas  or  oil.


                                        9
<PAGE>
<TABLE>
<CAPTION>
                             2004         2003         2002
                         ===========  ===========  ===========
                         Gross  Net   Gross  Net   Gross  Net
                         -----  ----  -----  ----  -----  ----
<S>                      <C>    <C>   <C>    <C>   <C>    <C>
DEVELOPMENT:
     Productive
    Appalachian           26.0  17.5   45.0  39.1   53.0  47.8
    Western/New Zealand    1.0   0.1    2.0   0.4    1.0   0.3
                         -----  ----  -----  ----  -----  ----
     Total                27.0  17.6   47.0  39.5   54.0  48.1
                         =====  ====  =====  ====  =====  ====

     Nonproductive
    Appalachian              -     -    3.0   2.7    1.0   0.9
    Western/New Zealand    1.0   0.1      -     -      -     -
                         -----  ----  -----  ----  -----  ----
     Total                 1.0   0.1    3.0   2.7    1.0   0.9
                         =====  ====  =====  ====  =====  ====
EXPLORATORY:
     Productive
    Appalachian            2.0   1.1    4.0   1.4    4.0   1.6
    Western/New Zealand      -     -    9.0   4.0    4.0   2.3
                         -----  ----  -----  ----  -----  ----
     Total                 2.0   1.1   13.0   5.4    8.0   3.9
                         =====  ====  =====  ====  =====  ====

     Nonproductive
    Appalachian            2.0   0.7    2.0   1.0    5.0   2.1
    Western/New Zealand    8.0   4.6    4.0   2.2    4.0   3.2
                         -----  ----  -----  ----  -----  ----
     Total                10.0   5.3    6.0   3.2    9.0   5.3
                         =====  ====  =====  ====  =====  ====
</TABLE>

                            ITEM 3. LEGAL PROCEEDINGS
                            -------------------------


     As  previously  reported,  the  Company had been in litigation with certain
Holders  of  its  $200,000,000  9 1/2%  Senior  Subordinated Notes due 2007 (the
"Noteholders")  (the  "Notes").  The dispute involved the calculation of the Net
Proceeds of an Asset Sale as defined in the Indenture dated May 23, 1997 between
the  Company  and  The  Bank  of  New York. The Company and the Noteholders have
settled  the dispute, as memorialized in the Settlement Agreement executed as of
February 24, 2004, and attached to the Form 8-K filed by the Company on February
24,  2004  as  Exhibit  99.11 (the "Settlement Agreement"). In settlement of the
dispute  the  Company agreed to repurchase $38 million in Notes. The Company has
met  its  obligations  under the Settlement Agreement having finalized the first
Asset Sale Offer (as defined under the Indenture) in the amount of $4 million on
March  24,  2004 and the second Asset Sale Offer in the amount of $34 million on
July  29,  2004.  The  United States District Court for the Southern District of
West  Virginia  has  entered  a  Dismissal  Order dismissing the litigation with
prejudice.

     The  Company  is involved in various other legal actions and claims arising
in  the  ordinary  course of business. While the outcome of these other lawsuits
against  the  Company  cannot  be  predicted with certainty, management does not
expect  these  matters  to  have  a  material  adverse  effect  on the Company's
operations  or  financial  position.


                                       10
<PAGE>
     ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     -----------------------------------------------------------

     None.


                                     PART II
                                     -------

                ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK
                ------------------------------------------------
                        AND RELATED STOCKHOLDER MATTERS
                        -------------------------------

     The  Company's  common  stock  is  not  traded  in  a public market.  As of
September  23,  2004,  the Company had 32 holders of record of its common stock.

     The  Company declared dividends in fiscal years 2004, 2003 and 2002 of $1.2
million,  $1.1  million  and  $1.1  million,  respectively.


                        ITEM 6. SELECTED FINANCIAL DATA
                        -------------------------------

<TABLE>
<CAPTION>
(Dollars in thousands, except per share items)

                                                            Year Ended June 30,
                                            ---------------------------------------------------
                                              2004      2003      2002       2001       2000
                                            --------  --------  ---------  ---------  ---------
<S>                                         <C>       <C>       <C>        <C>        <C>

Operating revenue                           $123,373  $117,426  $ 86,142   $129,951   $101,919
Income (loss) from operations                  4,295     9,917   (26,180)   (10,199)   (26,508)

  Earnings per common share, basic (a)          6.62     15.12    (39.80)    (15.34)    (40.11)
  Earnings per common share, diluted (a)        6.52     14.79    (39.80)    (15.34)    (40.11)
Total assets                                 290,212   295,834   304,736    380,532    265,691
Long term debt                               162,894   173,197   198,701    198,902    212,575
Dividends declared per common share         $   1.96  $   1.72  $   1.60   $   5.80   $      -
</TABLE>

     (a)  The  effect  of  outstanding  stock  options  was  not included in the
     computation  of  diluted  earnings per share for years ended 2002, 2001, or
     2000,  because  to  do  so  would  have  been  antidilutive.

           ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
           ----------------------------------------------------------
                       OPERATIONS AND FINANCIAL CONDITION
                       ----------------------------------


SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
--------------------------------------------------------------------------------

     This  discussion  and  analysis  of  financial  condition  and  results  of
operations,  and  other  sections  of  this  Form  10-K, contain forward-looking
statements  that  are  based  on  management's  beliefs,  assumptions,  current
expectations,  estimates,  intentions  and  projections  about  the  oil and gas
industry,  the  economy  and  about  the  Company  itself.  Words  such  as
"anticipates,"  "believes,"  "estimates," "expects," "forecasts," "intends," "is
likely,"  "plans,"  "predicts," "projects," variations of such words and similar
expressions  are  intended to identify such forward-looking statements under the
Private  Securities  Litigation  Reform  Act of 1995.  The Company cautions that
these  statements  are  not  guarantees  of  future  performance  and


                                       11
<PAGE>
involve  certain  risks,  uncertainties  and  assumptions  that are difficult to
predict  with  regard  to  timing,  extent, likelihood and degree of occurrence.
Therefore,  actual  results  and outcomes may materially differ from what may be
expressed  or  forecasted  in such forward-looking statements.  Furthermore, the
Company  undertakes  no  obligation  to update, amend or clarify forward-looking
statements,  whether as a result of new information, future events or otherwise.

     Important factors that could cause actual results to differ materially from
the  forward-looking  statements  include,  but  are  not  limited  to,  weather
conditions, changes in production volumes, worldwide demand and commodity prices
for  petroleum natural resources, the timing and extent of the Company's success
in  discovering,  acquiring,  developing  and  producing  oil  and  natural  gas
reserves,  risks  incident  to the drilling and operation of oil and natural gas
wells, future production and development costs, foreign currency exchange rates,
the  effect  of  existing  and  future  laws,  governmental  regulations and the
political  and economic climate of the United States and New Zealand, the effect
of  hedging  activities,  and  conditions  in  the  capital  markets.

     The  following  should  be read in conjunction with the Company's Financial
Statements  and  Notes  (including  the  segment  information) at Item 8 and the
Selected  Financial  Data  at  Item  6.

CRITICAL  ACCOUNTING  POLICIES  AND  ESTIMATES
-----------------------------------------------

     The  discussion  of financial condition and results of operation are based
upon  the  information  reported  in the consolidated financial statements.  The
preparation  of  these  financial  statements  requires  the  Company  to  make
assumptions  and  estimates  that  affect  the  reported  amounts  of  assets,
liabilities,  revenues  and  expenses  as  well  as the disclosure of contingent
assets  and  liabilities at the date of the financial statements.  Decisions are
based on historical experience and various other sources that are believed to be
reasonable  under  the  circumstances.  Actual  results  may  differ  from  the
estimates  due to changing business conditions or unexpected circumstances.  The
Company  believes  the  following  policies  are  critical  to understanding our
business  and  results of operations.  For additional information on significant
accounting  policies,  see  Notes  to  Consolidated  Financial  Statements,
particularly  Note  2.

     REVENUE  RECOGNITION  -  The  Company  is  engaged  in  the  exploration,
development,  acquisition,  production  and aggregation of natural gas and crude
oil.  The  revenue  recognition  policy  is  significant  because  it  is  a key
component  of the results of operations and forward looking statements contained
in  the  Liquidity  and Capital Resources section.  Revenue is derived primarily
from the sale of produced natural gas and crude oil.  Revenue is recorded in the
month  production  is  delivered  to  the  purchaser,  but  payment is generally
received  between  30  and  90  days after the date of production.  Monthly, the
Company  makes  estimates of the amount of production delivered to the purchaser
and  the  price  to  be received.  The Company uses its knowledge of properties,
historical  performance, NYMEX and local spot market prices and other factors as
the  basis  for these estimates.  Variances between the estimates and the actual
amounts  received, which historically have not been significant, are recorded in
the  month  revenue  is  distributed.

     DERIVATIVE  INSTRUMENTS  -  The  estimated  fair  values of all derivative
instruments  are  recorded  on  the  consolidated  balance  sheet.  All  of  the
derivative  instruments are entered into to mitigate risks related to the prices
to  be  received  for  future  natural  gas  and  oil  production.  Derivative
instruments  are  not  used  for  trading  purposes.  Although  derivatives  are
reported  on  the  balance  sheet  at fair value, to the extent that instruments
qualify  for hedge accounting treatment, changes in fair value are recorded, net
of taxes, directly to stockholders' equity as a component of other comprehensive
income  until  the  hedged  oil  or natural gas quantities are produced.  To the
extent  changes  in  the  fair  values  of derivatives relate to instruments not
qualifying  for  hedge  accounting  treatment,  such  changes  are  recorded  in
operations in the period they occur.  In determining the amounts to be recorded,
the  Company  is  required  to  estimate  the


                                       12
<PAGE>
fair  values  of derivatives.  The estimates are based upon various factors that
include  contract  volumes and prices, contract settlement dates, quoted closing
prices  on  the  NYMEX  or  over-the-counter,  volatility  and the time value of
options.  The  estimated  future  prices are compared to the prices fixed by the
derivatives  agreements  and  the  resulting  estimated  future  cash inflows or
outflows over the lives of the hedges are discounted to calculate the fair value
of  the  derivative  contracts.  These  pricing  and  discounting  variables are
sensitive  to market volatility as well as changes in future price forecasts and
regional  price  differences.  Periodically  the  valuations are validated using
independent  third  party  quotations.

     RESERVE  ESTIMATES  -  The  Company's estimate of gas and oil reserves are
projections  based  on  geologic  and engineering data.  There are uncertainties
inherent  in the interpretation of such data as well as the projection of future
rates  of  production  and  the  timing  of  development  expenditures.  Reserve
engineering  is  a subjective process of estimating underground accumulations of
gas and oil that are difficult to measure.  The accuracy of any reserve estimate
is  a  function  of  the  quality  of available data, engineering and geological
interpretation  and judgment.  Estimates of economically recoverable gas and oil
reserves  and future net cash flows depend upon a number of variable factors and
assumptions,  such  as  expected  future  production  rates, gas and oil prices,
operating  costs,  severance taxes, and development costs, all of which may vary
considerably  from  actual  results.  Expected cash flows are reduced to present
value  using  a  discount  rate  of  10%,  as  required by accounting standards.
Reserve  estimates are inherently imprecise and estimates of new discoveries are
more  imprecise  than  those  of  proved  producing oil and gas properties.  The
future  drilling  costs  associated with reserves assigned to proved undeveloped
locations  may  ultimately  increase  to  an  extent  that these reserves may be
determined  to be uneconomic.  Any significant variance in the assumptions could
materially  affect the estimated quantity and value of the reserves, which could
affect  the  carrying  value  of  the Company's gas and oil properties and their
rates of depletion.  Changes in these calculations, caused by changes in reserve
quantities  or  net  cash  flows  are  recorded  on a prospective basis.  Actual
production,  revenues  and  expenditures  with respect to the Company's reserves
will  likely  vary  from  estimates  and  such  variances  may  be  material.

     VALUATION OF LONG-LIVED AND INTANGIBLE ASSETS - Property and equipment are
recorded  at cost.  The carrying value of property and equipment is reviewed for
possible  impairment  whenever  events or changes in circumstances indicate that
the  carrying  amount  may  not  be  recoverable.  Assets  are  determined to be
impaired if a forecast of undiscounted estimated future net operating cash flows
directly related to the asset, including disposal value if any, is less than the
carrying  amount  of  the asset.  If any asset is determined to be impaired, the
loss is measured as the amount by which the carrying amount of the asset exceeds
its  fair  value.  An  estimate  of  fair value is based on the best information
available,  including  prices for similar assets.  Different pricing assumptions
or  discount  rates  would  result  in  a  different  calculated  impairment.

     INCOME  TAXES  -  The  Company  provides  for deferred income taxes on the
difference  between  the  tax  basis  of  an asset or liability and its carrying
amount  in  the  financial  statements.  This  difference will result in taxable
income  or  deductions  in future years when the reported amount of the asset or
liability  is  recovered or settled, respectively.  Federal and state income tax
returns are generally not filed before the consolidated financial statements are
prepared,  therefore  an  estimate of the tax basis of assets and liabilities is
determined at the end of each period as well as the effects of tax rate changes,
tax  credits  and  net  operating  loss  carryforwards.  Adjustments  related to
differences  between the estimates and actual amounts are recorded in the period
the  income  tax  returns  are  filed.

COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2004 AND 2003
--------------------------------------------------------------------------------

     The  Company  realized  net income of $4.3 million for the year ended June
30, 2004 compared to a net income of $9.8 million in 2003.  The decrease of $5.5
million  was primarily attributable to the net effect of a $5.9 million increase
in  revenue,  a  $3.9  million  decrease  in  costs and expenses, a $1.3 million


                                       13
<PAGE>
decrease  in  interest  expense,  $27.5  million decrease in interest income and
other  and  a  $10.8  million  decrease  in  income  tax  expense.

     OPERATING  MARGINS.  Operating  Margins (defined as revenue less operating
     ------------------
costs  and  taxes  other  than  income  taxes)  for  the  Company's  operating
subsidiaries  totaled  $51.7  million  for  the  current  year compared to $50.3
million  for  the  prior  period.  The  Company's  Oil  and Gas Operating Margin
(defined  as  oil  and  gas  sales and well operations and service revenues less
field  operating  expenses  and  taxes  other than income) totaled $46.8 million
versus $43.5 million for the prior year.  The Company's Aggregation and Pipeline
Operating  Margin  (defined  as  gas  aggregation  and  pipeline  sales less gas
aggregation  and  pipeline  cost  of sales) totaled $4.8 million for the current
period  versus  $6.8  million  for  the  prior  period.


                                       14
<PAGE>
     Production,  aggregation  and  pipeline volumes, revenue and average sales
prices  for  the years ended June 30 and their related variances are as follows:

<TABLE>
<CAPTION>
                                                        TWELVE MONTHS ENDED
                                                               JUNE 30                 VARIANCE
                                                      -----------------------  ------------------------
                                                         2004         2003       AMOUNT       PERCENT
                                                      -----------  ----------  -----------  -----------
<S>                                                   <C>          <C>         <C>          <C>
Natural Gas
    Production (Mmcf)                                     10,718       9,756          962          9.9%
    Average sales price received ($/Mcf)                    5.49        5.13         0.36          7.0%
                                                      -----------  ----------  -----------  -----------
    Sales ($ in thousands)                                58,851      50,031        8,820         17.6%
Oil
    Production (Mbbl)                                        107         104            3          2.9%
    Average sales price received ($/Bbl)                   29.94       25.97         3.97         15.3%
                                                      -----------  ----------  -----------  -----------
    Sales ($ in thousands)                                 3,204       2,701          503         18.6%
Hedging                                                   (5,213)     (4,843)        (370)         7.6%
Other                                                        361       3,521       (3,160)       -89.7%
                                                      -----------  ----------  -----------  -----------
Total oil and gas sales ($ in thousands)                  57,203      51,410        5,793         11.3%
                                                      ===========  ==========  ===========  ===========
Aggregation Revenue
    Volume (Million Mmbtu)                                 8,591       9,285         (694)        -7.5%
    Average sales price received ($/Mmbtu)                  5.22        4.86         0.36          7.4%
                                                      -----------  ----------  -----------  -----------
    Sales ($ in thousands)                                44,854      45,145         (291)        -0.6%
Pipeline Revenue
    Volume (Million Mmbtu)                                 5,528       5,675         (147)        -2.6%
    Average sales price received ($/Mmbtu)                  2.89        2.70         0.19          7.0%
                                                      -----------  ----------  -----------  -----------
    Sales ($ in thousands)                                15,965      15,338          627          4.1%
                                                      -----------  ----------  -----------  -----------
Total aggregation and pipeline sales ($ in thousands)     60,819      60,483          336          0.6%
                                                      ===========  ==========  ===========  ===========
Aggregation Gas Cost
    Volume (Million Mmbtu)                                 8,591       9,285         (694)        -7.5%
    Average price paid ($/Mmbtu)                            4.99        4.48         0.51         11.4%
                                                      -----------  ----------  -----------  -----------
    Cost ($ in thousands)                                 42,827      41,636        1,191          2.9%
Pipeline Gas Cost
    Volume (Million Mmbtu)                                 4,469       4,550          (81)        -1.8%
    Average price paid ($/Mmbtu)                            2.96        2.65         0.31         11.7%
                                                      -----------  ----------  -----------  -----------
    Cost ($ in thousands)                                 13,232      12,057        1,175          9.7%
                                                      -----------  ----------  -----------  -----------
Total aggregation and pipeline cost ($ in thousands)      56,059      53,693        2,366          4.4%
                                                      ===========  ==========  ===========  ===========
-------------------------------------------------------------------------------------------------------
</TABLE>


     REVENUES.  Total  revenues  increased  $5.9  million  or  5.1% between the
     --------
years.  The  net  increase  was  due to a 11.3% increase in oil and gas sales, a
0.6%  increase  in  gas  aggregation and pipeline sales, a 4.9% decrease in well
operations  and  service  revenues  and  a  248.6%  increase  in other operating
revenue.


                                       15
<PAGE>
     Revenues from oil and gas sales increased  $5.8 million from $51.4 million
for  the  year  ended June 30, 2003 to $57.2 million for the year ended June 30,
2004.  Natural  gas  sales  increased  $8.8 million and oil sales increased $0.5
million.  The  increase is a result of an increase in both price and production.
The price increase corresponds with related indexes.  The increase in production
was  attributable  to  a  decrease  in  extended  curtailments  on  third  party
transmission  facilities  compared  to  the  prior  year and the drilling of new
wells.  The  increased  production  revenue  was  offset by recognized losses on
related  hedging  transactions  including derivative instruments and fixed price
delivery contracts, which totaled a loss of $5.2 million for the year ended June
30,  2004  compared  to a loss of $4.8 million for the year ended June 30, 2003.
Other  gas  sales  decreased  $3.2  million  as  a  result of $3.1 million being
recognized  in  the  year  ended  June  30,  2003 related to the termination and
release  of  a certain gas contract.  The average price per Mcfe, after hedging,
was  $5.03  and  $4.95 for the years ended June 30, 2004 and 2003, respectively.

     Revenues  from  gas  aggregation and pipeline sales increased $0.3 million
from $60.5 million during the period ended June 30, 2003 to $60.8 million in the
period  ended  June  30,  2004.  Gas  aggregation revenue decreased $0.3 million
while  pipeline revenue, which has sale and transportation components, increased
$0.6  million.  The  increase  in  gas  aggregation  and  pipeline  sales  is
attributable to the increase in average sales price received offset by a decline
in  production.  The  price  increase  corresponds  with  related  indexes.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses decreased $3.9
     --------------------
million  or  3.5%  between  the  periods  primarily  as  a net result of a 13.1%
increase  in  field  and  lease  operating  expenses,  a  4.4%  increase  in gas
aggregation  and  pipeline  costs, a 0.9% increase in general and administrative
expenses,  a  26.9%  increase in taxes other than income, a 9.6% increase in oil
and  gas  related  depletion,  a  2.4% decrease in depreciation and amortization
expenses  of  pipelines, property and equipment,  a 8.0% decrease in exploration
and  impairment  costs,  and  a gain on sale of assets compared to a loss in the
prior  year.

     Field  and  lease operating expenses increased $1.3 million.  The increase
in  lease  operating  expenses  is  primarily  related to an increase in payroll
expenses,  medical  expense, and lease operating expenses  for new wells drilled
during  the  fiscal  year.

     Gas  aggregation  and  pipeline  costs  increased  $2.4  million.  Gas
aggregation  cost increased $1.2 million while pipeline cost also increased $1.2
million.  The  increase  in  gas  aggregation  and  pipeline  cost  of  sales is
attributable  to  the  increase  in  average  price  paid offset by a decline in
production.  The  price  increase  corresponds  with  related  indexes.

     Taxes  other  than  income increased $0.9 million as a result of increased
wellhead  oil  and  gas  sales.

     Oil  and  gas  related  depreciation,  depletion and amortization expenses
increased $1.2 million.  The increase in depletion is primarily due to increased
production  volumes  and  an  increase  in  depletion  rate.

     Gain  or loss on sale of property went from a loss of $0.4 million for the
year  ended  June 30, 2003 to a gain of $8.3 million for the year ended June 30,
2004.  The  primary  reason for the gain in the current fiscal year was the sale
of  the  Company's  membership interest in Breitburn Energy Company, LLC ("BEC")
for gross proceeds of $9.2 million.  A gain of $7.4 million was recognized and a
liability  of  $1.8 million established as a reserve against items for which the
Company  was  required  to  indemnify  the  buyer for a period of 180 days after
closing  pursuant  to  the  agreement.  The  Company  also sold acreage position
holdings  for  a  gain  of  $0.6  million  during  the  current  fiscal  year.


                                       16
<PAGE>
     Exploration  and impairment expenses decreased $0.9 million.  The decrease
is a result of lower expenses primarily related to dry hole costs, impairment of
oil  and  gas  property  and  various  other  geological  and geophysical costs.

     INTEREST  EXPENSE.  Interest  expense decreased $1.3 million primarily due
     ------------------
to  the  reduction  of  outstanding  debt  and  also  replacing a portion of the
Company's  debt  at  a  lower  interest  rate  for the year ended June 30, 2004.

     INTEREST  INCOME  AND  OTHER.  Other  non-operating income decreased $27.5
     ----------------------------
million  when  compared to the prior year.  The decrease is primarily the result
of a decrease of $23.2 million associated with the gains recognized on the early
retirement  of bonds and a $4.5 million gain on a legal settlement that occurred
in  fiscal  year  2003.

     INCOME  TAX.  Income  tax expense decreased by $10.8 million in 2004 to an
     -----------
income  tax benefit of $4.7 million as compared to an income tax expense in 2003
of  $6.1  million.  The  decrease  is primarily due to the adjustment of the tax
contingency  balance  of  $4.5  million  for  items that are closed or no longer
applicable  and  the  decrease  in  income before income taxes of $16.4 million.

COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2003 AND 2002
--------------------------------------------------------------------------------

     The  Company  recorded net income  of $9.8 million for the year ended June
30,  2003  compared  to a net loss of $26.2 million in 2002.  The improvement of
$36.0  million  was  primarily attributable to the net effect of a $31.3 million
increase  in  revenue,  a  $0.5  million  increase in costs and expenses, a $3.3
million  decrease  in  interest  expense,  a  $24.7  million  increase  in other
non-operating  income  and  a  $22.9  million  increase  in  income tax expense.

     OPERATING  MARGINS.  Operating  Margins (defined as revenue less operating
     ------------------
costs  and  taxes  other  than  income  taxes)  for  the  Company's  operating
subsidiaries  totaled  $50.3  million  for  the  current  year compared to $35.6
million  for  the  prior  period.  The  Company's  Oil  and Gas Operating Margin
(defined  as  oil  and  gas  sales and well operations and service revenues less
field  operating  expenses  and  taxes  other than income) totaled $43.5 million
versus $31.3 million for the prior year.  The Company's Aggregation and Pipeline
Operating  Margin  (defined  as  gas  aggregation  and  pipeline  sales less gas
aggregation  and  pipeline  cost  of sales) totaled $6.8 million for the current
period  versus  $3.7  million  for  the  prior  period.  Other revenue was $0.04
million  for  the  current  period  versus  $0.5  million  for the prior period.


                                       17
<PAGE>
     Production,  aggregation  and  pipeline volumes, revenue and average sales
prices  for  the years ended June 30 and their related variances are as follows:

<TABLE>
<CAPTION>
                                                       TWELVE MONTHS ENDED
                                                              JUNE 30                VARIANCE
                                                      ----------------------  ------------------------
                                                         2003        2002       AMOUNT       PERCENT
                                                      -----------  ---------  -----------  -----------
<S>                                                   <C>          <C>        <C>          <C>
Natural Gas
    Production (Mmcf)                                      9,756       9,941        (186)        -1.9%
    Average sales price received ($/Mcf)                    5.13        2.86        2.27         79.1%
                                                      -----------  ---------  -----------  -----------
    Sales ($ in thousands)                                50,031      28,462      21,569         75.8%
Oil
    Production (Mbbl)                                        104         124         (20)       -16.1%
    Average sales price received ($/Bbl)                   25.97       21.11        4.86         23.0%
                                                      -----------  ---------  -----------  -----------
    Sales ($ in thousands)                                 2,701       2,618          83          3.2%
Hedging                                                   (4,843)      7,212     (12,055)      -167.2%
Other                                                      3,521         647       2,874        444.2%
                                                      -----------  ---------  -----------  -----------
Total oil and gas sales ($ in thousands)                  51,410      38,939      12,471         32.0%
                                                      ===========  =========  ===========  ===========
Aggregation Revenue
    Volume (Million Mmbtu)                                 9,285       9,903        (618)        -6.2%
    Average sales price received ($/Mmbtu)                  4.86        3.14        1.72         54.7%
                                                      -----------  ---------  -----------  -----------
    Sales ($ in thousands)                                45,145      31,125      14,020         45.0%
Pipeline Revenue
    Volume (Million Mmbtu)                                 5,675       6,003        (328)        -5.5%
    Average sales price received ($/Mnbtu)                  2.70        1.68        1.02         60.9%
                                                      -----------  ---------  -----------  -----------
    Sales ($ in thousands)                                15,338      10,084       5,254         52.1%
                                                      -----------  ---------  -----------  -----------
Total aggregation and pipeline sales ($ in thousands)     60,483      41,209      19,274         46.8%
                                                      ===========  =========  ===========  ===========
Aggregation Gas Cost
    Volume (Million Mmbtu)                                 9,285       9,902        (617)        -6.2%
    Average price paid ($/Mmbtu)                            4.48        2.98        1.50         50.4%
                                                      -----------  ---------  -----------  -----------
    Cost ($ in thousands)                                 41,636      29,526      12,110         41.0%
Pipeline Gas Cost
    Volume (Million Mmbtu)                                 4,550       4,870        (320)        -6.6%
    Average price paid ($/Mmbtu)                            2.65        1.64        1.01         62.0%
                                                      -----------  ---------  -----------  -----------
    Cost ($ in thousands)                                 12,057       7,963       4,094         51.4%
                                                      -----------  ---------  -----------  -----------
Total aggregation and pipeline cost ($ in thousands)      53,693      37,489      16,204         43.2%
                                                      ===========  =========  ===========  ===========
</TABLE>



     REVENUES.  Total  revenues  increased  $31.3  million or 36.3% between the
     --------
years.  The  net  increase  was  due to a 32.0% increase in oil and gas sales, a
46.8%  increase  in  gas aggregation and pipeline sales, a 0.1% increase in well
operations and service revenues and a 93.1% decrease in other operating revenue.


                                       18
<PAGE>
     Revenues  from  oil  and  gas  sales increased a net of $12.5 million from
$38.9  million  for  the  year ended June 30, 2002 to $51.4 million for the year
ended  June  30,  2003.  Natural gas sales increased $21.6 million and oil sales
increased  $0.08  million.  The price increase corresponds with related indexes.
The  decrease  in  production was due in part to the sale of certain oil and gas
properties,  extended  curtailments  on  third party transmission facilities, as
well  as  normal  production declines.  The decrease in production was partially
offset by the purchase of certain oil and gas properties and the drilling of new
wells.  The  increased  production  revenue  was  offset by recognized losses on
related  hedging  transactions  including derivative instruments and fixed price
delivery contracts, which totaled a loss of $4.8 million for the year ended June
30,  2003  compared  to a gain of $7.2 million for the year ended June 30, 2002.
The  average  price  per  Mcfe, after hedging, was $4.95 and $3.65 for the years
ended  June  30,  2003  and  2002,  respectively.

     Revenues  from  gas aggregation and pipeline sales increased $19.3 million
from $41.2 million during the period ended June 30, 2002 to $60.5 million in the
period  ended  June  30,  2003.  Gas aggregation revenue increased $14.0 million
while  pipeline revenue, which has sale and transportation components, increased
$5.3  million.  The  increase  in  gas  aggregation  and  pipeline  sales  is
attributable  to  the  increase  in  average  sales  price  received.  The price
increase  corresponds  with  related  indexes.

     Other  operating  revenue decreased $0.5 million.  The current year income
of  $0.03 million is related to revenue earned by the Company's participation in
Deep  Rig,  L.P.,  while  $0.5  million  was  recognized  in  the  prior  year.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses increased $0.5
     --------------------
million or 0.5% between the periods primarily as a net result of a 7.2% decrease
in  field  and lease operating expenses, a 43.2% increase in gas aggregation and
pipeline costs, a 11.1% decrease in general and administrative expenses, a 51.1%
increase  in  taxes  other  than  income, a 1.8% decrease in oil and gas related
depreciation,  a  46.4%  increase  in  depletion  and  amortization  expenses of
pipelines,  property  and  equipment,  a  57.6%  decrease  in  exploration  and
impairment  costs,  and  a  gain  instead  of  a  loss  on  sale  of  assets.

     Field  and  lease operating expenses decreased $0.8 million.  The decrease
in  lease  operating  expenses  is  primarily related to a reduction in contract
labor  expenses,  road  and dike repair costs, and various other field and lease
operating  expenses.

     Gas  aggregation  and  pipeline  costs  increased  $16.2  million.  Gas
aggregation  cost  increased  $12.1  million while pipeline costs increased $4.1
million.  The  increase  in  gas  aggregation  and  pipeline  cost  of  sales is
attributable  to  the  increase  in  average  price  paid.  The  price  increase
corresponds  with  related  indexes.

     General  and  administrative expenses decreased $1.9 million primarily due
to  an increase in exploration and development drilling capitalized costs, lower
bad  debt  expense,  legal  fees,  and  board  fees.

     Taxes  other  than  income increased $1.1 million as a result of increased
oil  and  gas  sales.  Average  wellhead  oil  and  gas  sales  prices, on which
production  taxes  are  based,  were  higher  for  the  current  year.

     Oil  and  gas  related  depreciation,  depletion and amortization expenses
decreased  $0.2  million.  The decrease in depletion is primarily due to reduced
production volumes resulting from the sale of certain oil and gas properties and
normal  production  declines,  partially  offset  by  production  related to the
acquisition  of certain oil and gas properties and from new wells drilled during
the  year.


                                       19
<PAGE>
     Exploration  and  impairment  expenses  decreased  $16.0  million.  In the
current  year,  the expenses were primarily due to dry hole costs, impairment of
oil  and  gas  property  and  various  other  geological  and geophysical costs.

     INTEREST  EXPENSE.  Interest  expense decreased $3.3 million primarily due
     ------------------
to  the repurchase of $65.6 million face value of the Company's senior notes for
the  year  ended  June  30,  2003.

     INTEREST  INCOME  AND  OTHER.  Other  non-operating income increased $24.7
     ----------------------------
million when comparing the periods.  This is primarily the result of the Company
purchasing  a  portion  of  its  senior  bonds  and  recognizing a gain of $23.7
million.  The  Company  also  recognized  $4.5  million  in  income  from  legal
settlements  and  $1.4  million  in  net  contract  settlements  associated with
Allegheny  Energy.  Offsetting this increase in other non-operating income was a
reduction  in  interest  income  of  $1.1  million  due to decreases in the cash
balances  and  interest  rates  when  comparing  the  periods.  The Company also
recognized  a  loss  of  $2.1 million due to the write down of its investment in
Alliance  Gas.

     INCOME  TAX.  Income  tax expense increased by $22.9 million in 2003 to an
     -----------
income  tax expense of $6.1 million as compared to an income tax benefit in 2002
of  $16.8  million.  This increase was due to a $58.8 million increase in income
before  income  taxes.

CAPITAL  EXPENDITURES
----------------------

          Expenditures  for the exploration, development and acquisition of oil
and  gas  properties  are  the  Company's primary use of capital resources.  The
following  table  summarizes  certain costs incurred for the years ended June 30
(in  thousands):

                              2004     2003     2002
                             -------  -------  -------
          Development        $ 7,892  $14,105  $10,977
          Exploration         10,449   15,292   20,737
          Acquisitions            72    5,879      717
                             -------  -------  -------
            Total            $18,413  $35,276  $32,431
                             =======  =======  =======

ACQUISITIONS
------------

     The  Company finalized the purchase of an additional 100-mile long natural
gas  gathering  system  ("System  8000")  from  Columbia  Gas Transmission for a
purchase  price  of  $1.2  million during the first quarter of fiscal year 2005.
System 8000 is located in northeastern West Virginia and is situate among one of
the  Company's  existing  operating  areas.

     On  February 5, 2003, the Company purchased certain oil and gas properties
located  in  southern West Virginia for $5.6 million, after certain adjustments.
The  purchase  included  proved developed producing gas reserves, estimated at 4
Bcf,  90  producing  wells  and  over  30,000  acres.

LIQUIDITY  AND  CAPITAL  RESOURCES
----------------------------------

     The  Company's  financial condition and liquidity have improved since June
30,  2003.  Stockholders'  equity  has  decreased from $43.7 million at June 30,
2003  to $42.4 million at June 30, 2004.  The Company's cash increased from $4.8
million  at  June 30, 2003 to $5.8 million at June 30, 2004.  The Company's cash
at  September  23, 2004 was $0.9 million.  The change in cash during the year of
approximately  $1.0  million  resulted  from  various  operating,  investing and
financing  activities  of  the


                                       20
<PAGE>
Company.  The  activities  were  primarily  comprised  of:  the  paydown  of
approximately  $3.1  million under the Company's $50 million revolving loan; the
net  investment of approximately $22.0 million in property, plant and equipment;
payments  of  approximately  $5.5  million  for the purchase of a portion of the
Company's  outstanding  Notes;  payments  of  approximately $3.0 million for the
acquisition  of  treasury  stock  and  dividends; cash received of approximately
$10.8 million from the sale of assets; $1.5 million received from the collection
of  a  note  receivable;  receipt  of  approximately  $0.3  million  of  cash in
connection  with  the  Company's  restricted  Class  A  stock  purchase plan for
employees; and approximately $22.0 million of cash provided by operations during
the  year.

     On  June  15,  2004  the Company sold its membership interest in Breitburn
Energy Company, LLC ("BEC") for gross proceeds of $9.2 million.  Pursuant to the
terms  of  its  Senior  Subordinated  Notes  (the  "Notes"), the Company has the
option,  within  360  days  of  receipt of the "Net Proceeds" (as defined in the
Indenture  dated  May 23, 1997 between the Company as Issuer and The Bank of New
York  as  Trustee,  hereinafter the "Indenture") from the sale of the membership
interest  in  BEC,  to  apply such proceeds to (a) reduce debt senior to or pari
passu  with  the  Notes  (provided that in connection with the reduction of pari
passu  debt,  a  pro  rata  portion  of  the  Notes  is redeemed); (b) acquire a
controlling  interest  in  another  business  engaged  in  either  natural  gas
distribution  or  the exploration, development or operation of oil, gas or other
hydrocarbon  properties (an "Energy Business"); (c) make capital expenditures in
respect  of  the  Company's or its restricted subsidiaries' Energy Business; (d)
purchase long term assets that are used or useful in the Energy Business; or (e)
repurchase the Notes.  If the Company has not applied all of the Net Proceeds in
accordance  with  one  of  the  above options within 360 days of receipt of such
proceeds,  then  with respect to those Net Proceeds that were not applied to one
of  the  above  options, such Net Proceeds are then deemed to constitute "Excess
Proceeds".  To  the  extent  the Excess Proceeds exceed $10 million, the Company
must make an offer to the holders of the Notes, (and holders of pari passu debt,
to  the  extent  required by the terms of the pari passu debt) to repurchase the
maximum  principal  amount  of  the  Notes  and  any pari passu debt that may be
purchased  out of the Excess Proceeds at an offer price in cash equal to 100% of
the  principal  amount  thereof, plus accrued and unpaid interest thereon to the
date  of the purchase.  The Company anticipates that the requirement to reinvest
the  Net  Proceeds  will be met by its budgeted capital expenditures program for
the  year  ending  June  30,  2005.

     As  previously  reported, on July 10, 2002, the Company entered into a $50
million  revolving Credit Agreement with Foothill Capital Corporation, now Wells
Fargo  Foothill,  Inc. ("Foothill").  The Company and Foothill have entered into
an  Amended  and  Restated  Credit  Agreement dated June 10, 2004 (the "Restated
Credit  Agreement").  The Restated Credit Agreement provides for the $50 million
revolving credit facility to be extended and for the Company to be provided with
additional credit in the form of a single advance term loan in the amount of $50
million.  The  term  loan  contains  requirements  for  principal payments of $1
million  each at July 10, 2005, 2006 and 2007, with the remaining balance due on
July 10, 2008.  Depending on the Company's level of borrowing under the Restated
Credit Agreement, the applicable interest rates for base rate loans are based on
Wells Fargo's prime rate plus 0.25% to 0.75%.  The Company has the ability under
the  Restated Credit Agreement to designate certain loans as Libor Rate Loans at
interest rates based upon the rate at which dollar deposits are offered to major
banks  in  the London interbank market plus 2.25% to 2.75%.  The Restated Credit
Agreement  expires  on  July  10,  2008.

     The obligations under the Restated Credit Agreement are secured by certain
of  the  existing  proved  producing  oil  and  gas  assets of the Company.  The
Restated  Credit  Agreement,  among  other  things, restricts the ability of the
Company  and  its  subsidiaries  to  incur  new  debt, grant additional security
interests  in  its  collateral,  engage  in  certain  merger  or  reorganization
activities,  or  dispose  of  certain  assets.

     At June 30, 2004, the Company's principal source of liquidity consisted of
$5.8  million of cash, $0.2 million available under an unsecured credit facility
currently  in  place,  plus  amounts  available  under


                                       21
<PAGE>
both the term loan and revolving loan of the Restated Credit Agreement.  At June
30,  2004,  $1.0  million was outstanding and $1.8 million was committed through
letters  of  credit  under  the short-term credit facility and $36.1 million was
outstanding  on  the  revolving loan under the Restated Credit Agreement.  There
were  no  amounts  outstanding  on the $50 million term loan available under the
Restated  Credit  Agreement.

     As  previously  reported,  the Company had been in litigation with certain
Holders  (the "Noteholders") of its Notes.  The dispute involved the calculation
of  "Net  Proceeds" of an "Asset Sale" as defined in the Indenture. A settlement
agreement  dated  February  24,  2004,  was  negotiated  with the Noteholders to
resolve  the  dispute.  In  settlement  of  the  dispute  the  Company agreed to
repurchase  $38  million  in  Notes.  The repurchase was effected by the Company
making  Asset  Sale  Offers  (as defined in the Indenture) totaling $38 million.
The  Company made an initial Asset Sale Offer of $4 million, which was completed
on  March  25,  2004.  The  Company  consummated another Asset Sale Offer of $34
million  which  was  completed  on  July 29, 2004.    The United States District
Court  for  the Southern District of West Virginia has entered a Dismissal Order
dismissing  the  litigation  with prejudice. Upon the Company meeting all of the
terms  and conditions of the Settlement Agreement it funded the $50 million term
loan  under  the  Restated  Credit  Agreement.

     As  of  September 23, 2004, there are $50 million in outstanding borrowings
under  the  term  loan  and  $15  million  in  outstanding  borrowings under the
revolving  loan.  Additional  borrowings  must  comply  with  the  terms  of the
Indenture  and  the  Foothill  Amended  and  Restated  Credit  Agreement.

     The Company's net cash requirements will fluctuate based on timing and the
extent  of  the interplay of capital expenditures, cash generated by operations,
cash  generated  by  the  sale  of assets and interest expense.  EBITDAX, before
inclusion  of  the  gain on the purchase of the Company's Notes, for fiscal year
2004  was  $42.4 million.  EBITDAX for fiscal years 2003 and 2002, measured on a
similar  basis,  was  $36.9 million and $19.7 million, respectively.  Management
anticipates  that  EBITDAX from oil and gas operations for fiscal year 2005 will
approximate  $44  million.  The  Company's  ability  to  achieve  EBITDAX of $44
million  from oil and gas operations for fiscal year 2005 is highly dependant on
product  price  and  continued  drilling success.  Management believes that cash
generated  from  oil and gas operations, together with the liquidity provided by
existing  cash  balances and permitted borrowings, will be sufficient to satisfy
commitments  for  budgeted  capital  expenditures of $29.8 million, debt service
obligations,  working  capital  needs  and  other cash requirements for the next
fiscal  year.

     In  order  to  reduce  future  cash  interest  payments, as well as future
amounts  due at maturity or upon redemption, the Company may, from time to time,
purchase  its  outstanding  Notes  in  open  market  purchases  and/or privately
negotiated  transactions.  The  Company  will  evaluate any such transactions in
light  of  then  existing  market conditions, taking into account its liquidity,
uses  of  capital  and  prospects  for  future  access  to capital.  The amounts
involved  in  any  such  transaction,  individually  or in the aggregate, may be
material.

     The  Company  believes  that  its  existing  capital  resources, permitted
borrowings  and  its  expected  fiscal  year 2005 results of operations and cash
flows  from operating activities will be sufficient for the Company to remain in
compliance with the requirements of its Notes and the Restated Credit Agreement.
However,  since  future  results  of  operations,  cash  flow  from  operating
activities,  debt  service  capability,  levels  and  availability  of  capital
resources and continuing liquidity are dependent on future weather patterns, oil
and  gas  commodity  prices and production volume levels, future exploration and
development  drilling  success  and  successful  acquisition  transactions,  no
assurance  can  be  given  that  the  Company will remain in compliance with the
requirements  of  its  Notes  and  the  Restated  Credit  Agreement.


                                       22
<PAGE>
     In  addition  to  the Restated Credit Agreement, unsecured credit facility
and  Notes  discussed  above,  the  Company  had various other obligations.  The
following table lists the Company's contractual obligations at June 30, 2004 (in
thousands):

<TABLE>
<CAPTION>
                                      Payments due by period (in thousands)
                                                               More
                                Less than    1 - 3    3 - 5   than 5
                                  1 year     years    years    years     Total
                                ----------  -------  -------  -------  ---------
<S>                             <C>         <C>      <C>      <C>      <C>
 Senior subordinated notes (a)  $   34,000  $92,033  $     -  $     -  $ 126,033
 Revolving loan                      1,000        -   36,109        -     37,109
 Installment notes payable             145      224      127      401        897
 Mandatorily redeemable stock          202      479      702        -      1,383
 Operating leases                    1,131      883      677      543      3,234
                                ----------  -------  -------  -------  ---------
 Total contractual cash
 obligations                    $   36,478  $93,619  $37,615  $   944  $ 168,656
                                ==========  =======  =======  =======  =========
</TABLE>

(a)  The  Company  met  its' current obligation through the Asset Sale Offer for
$34  million  of its Senior Subordinated Notes which was consummated on July 29,
2004.


RECENT  ACCOUNTING  PRONOUNCEMENTS
----------------------------------

     In  March 2004, the Emerging Issues Task Force ("EITF") reached a consensus
that  mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights
Are  Tangible or Intangible Assets," are tangible assets and that they should be
removed  as  examples  of  intangible  assets  in  SFAS  No.  141,  "Business
Combinations"  and No. 142, "Goodwill and Other Intangible Assets." The FASB has
recently  ratified this consensus and directed the FASB staff to amend SFAS Nos.
141  and  142 through the issuance of FASB Staff Position ("FSP") FAS Nos. 141-1
and  142-1.  In  addition,  proposed  FSP  142-b confirms that SFAS 142 does not
change  the balance sheet classification or disclosures of mineral rights of oil
and  gas producing enterprises. Historically, the Company has included the costs
of  such  mineral rights as tangible assets, which is consistent with the EITF's
consensus.  As  such,  EITF  04-02  and  the  related FSPs have not affected the
Company's  consolidated  financial  statements.

     In May 2003 the FASB issued Statement of Financial Accounting Standards No.
150,  "Accounting for Certain Financial Instruments with Characteristics of both
Liabilities  and  Equity".  SFAS No. 150 establishes standards for how an issuer
classifies  and  measures  certain financial instruments with characteristics of
both liabilities and equity, and requires instruments that fall within the scope
of  this  pronouncement  to  be  classified  as  liabilities.  The Company early
adopted  SFAS  No.  150 at the beginning of the fourth quarter of the year ended
June  30,  2004.  The  effect  of this adoption was an increase to other current
liabilities  of  $0.2 million, other long term obligations of $1.2 million and a
$1.4  million  decrease  in  stockholders'  equity.


                                       23
<PAGE>
                ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
                -------------------------------------------------
                                ABOUT MARKET RISK
                                -----------------

COMMODITY  RISK
----------------

     The  Company's  operations  consist primarily of exploring for, producing,
aggregating  and  selling  natural  gas  and  oil.  Contracts  to deliver gas at
pre-established prices mitigate the risk to the Company of falling prices but at
the  same time limit the Company's ability to benefit from the effects of rising
prices.  The  Company  occasionally  uses  derivative  instruments  to hedge its
commodity price risk.  The Company hedges a portion of its projected natural gas
production  through a variety of financial and physical arrangements intended to
support  natural  gas  prices  at  targeted levels and to manage its exposure to
price  fluctuations.  The  Company may use futures contracts, swaps, options and
fixed  price  physical  contracts to hedge its commodity prices.  Realized gains
and losses from the Company's price risk management activities are recognized in
oil and gas sales when the associated production occurs.  Unrecognized gains and
losses are included as a component of other comprehensive income.  See Note 4 to
the  Consolidated  Financial Statements for additional information.  The Company
does not hold or issue derivative instruments for trading purposes.  The Company
has  elected  to  enter into various transactions, covering approximately 45% to
50% of its estimated natural gas production for the fiscal year ended June 2005.

As of June 30, 2004, the Company's open gas derivative instruments and fixed
price delivery contracts were as follows:

<TABLE>
<CAPTION>
                                             Total      Average
                                   Market   Volumes    Contract      Unrealized
Time period                        Index    (MMBtu)      Price     (Gains) Losses
---------------------------------  ------  ----------  ---------  ----------------
<S>                                <C>     <C>         <C>        <C>
Derivatives
  Natural Gas Swaps
    July 2004 - December 2004      NYMEX       25,000  $    5.20  $       (34,727)
    December 2004 - February 2005  NYMEX      300,000       6.12          183,667
    July 2004 - March 2005         NYMEX    1,080,000       5.57          915,180
    July 2004 - March 2005         NYMEX      810,000       5.61          654,857
    July 2004 - June 2005          NYMEX    2,160,000       4.54        5,549,623
                                           ----------             ----------------
    Unrealized Losses                       4,375,000             $     7,268,600
                                           ----------             ================
Physical Contracts
  Fixed Price Delivery Contracts
    July 2004 - October 2004                  338,250  $    4.85
                                           ----------
Total Hedged Production                     4,713,250
                                           ==========
</TABLE>

     Notwithstanding the above, the Company's future cash flows from gas and oil
production  are  exposed  to  significant volatility as commodity prices change.
Assuming  total  oil  and  gas  production  and the percentage of gas production
hedged  or  subject  to  fixed price contracts remain at June 2004 levels, a 10%
change  in the average unhedged prices realized during the year would change the
Company's gas and oil revenues by approximately $0.8 million on an annual basis.


                                       24
<PAGE>
INTEREST  RATE  RISK
--------------------

     Interest  rate  risk  is  attributable to the Company's debt.  The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment  needs.  As  of June 30, 2004, all but $36.9 million of the Company's
debt  has  fixed interest rates.  There is inherent rollover risk for borrowings
as they mature and are renewed at current market rates.  The extent of this risk
is  not  predictable because of the variability of future interest rates and the
Company's  future financing needs.  Assuming the variable interest debt remained
at  the June, 2004 level, a 10% change in rates would have a $0.2 million impact
on  interest expense on an annual basis.  The Company has not attempted to hedge
the  interest  rate  risk  associated  with  its  debt.

FOREIGN  CURRENCY  EXCHANGE  RISK
---------------------------------

     Some of the Company's transactions are denominated in New Zealand dollars.
For  foreign  operations  with  the  local  currency as the functional currency,
assets  and  liabilities  are  translated  at the period end exchange rates, and
statements  of  income  are  translated at the average exchange rates during the
period.  Gains  and  losses  resulting  from  foreign  currency  translation are
included  as  a  component  of  other  comprehensive  income.

                                   * * * * *


                                       25
<PAGE>
              ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
              -----------------------------------------------------



REPORT  OF  INDEPENDENT  REGISTERED  PUBLIC  ACCOUNTING  FIRM
--------------------------------------------------------------

To  the  Stockholders  and Board of Directors of Energy Corporation of America:

     We  have  audited  the  accompanying consolidated balance sheets of Energy
Corporation  of America and subsidiaries (the "Company") as of June 30, 2004 and
2003,  and  the  related  consolidated  statements  of operations, stockholders'
equity,  cash  flows and comprehensive income (loss) for each of the three years
in  the  period  ended  June  30,  2004.  These  financial  statements  are  the
responsibility  of the Company's management. Our responsibility is to express an
opinion  on  these  financial  statements  based  on  our  audits.

     We conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements  are free of material misstatement. An audit includes examining, on a
test  basis,  evidence  supporting  the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made  by  management,  as well as evaluating the overall
financial  statement  presentation.  We  believe  that  our  audits  provide  a
reasonable  basis  for  our  opinion.

     In  our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of June 30, 2004
and  2003  and  the results of their operations and their cash flows for each of
the  three  years  ended  June 30, 2004 in conformity with accounting principles
generally  accepted  in  the  United  States  of  America.

     As  discussed  in Note 2 to the consolidated financial statements, in 2003
the  Company  adopted  Statement  of  Financial  Accounting  Standards  No. 143,
"Accounting  for  Asset Retirement Obligations" and in 2004 adopted Statement of
Financial  Accounting  Standards  No.  150,  "Accounting  for  Certain Financial
Instruments  with  Characteristics  of  both  Liabilities  and  Equity".




DELOITTE  &  TOUCHE  LLP
Denver,  Colorado
September  27,  2004


                                       26
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  BALANCE  SHEETS
AS  OF  JUNE  30
(AMOUNTS IN THOUSANDS)
----------------------------------------------------------------------------

ASSETS                                                 2004         2003
                                                  ------------  ------------
<S>                                               <C>           <C>
CURRENT ASSETS:
  Cash and cash equivalents                       $     5,821   $     4,831
  Accounts receivable:
    Oil and gas sales                                   8,632        10,380
    Gas aggregation and pipeline                        9,079         9,458
    Other                                               4,000         4,616
                                                  ------------  ------------
      Accounts receivable                              21,711        24,454
   Less allowance for doubtful accounts                (1,022)       (1,616)
                                                  ------------  ------------
      Accounts receivable, net of allowance            20,689        22,838

  Deferred income tax asset                             2,087            41
  Deferred taxes - other comprehensive loss             2,889           787
  Notes receivable, related party                          59         1,609
  Prepaid and other current assets                      4,141         1,410
                                                  ------------  ------------
      Total current assets                             35,686        31,516

NET PROPERTY, PLANT AND EQUIPMENT (Note 2)            246,391       253,270
                                                  ------------  ------------

OTHER ASSETS:
  Deferred financing costs, less accumulated
    amortization of $6,833 and $5,751                   2,015         3,098
  Notes receivable, related party                         113           146
  Other                                                 6,007         7,804
                                                  ------------  ------------
      Total other assets                                8,135        11,048
                                                  ------------  ------------

TOTAL                                             $   290,212   $   295,834
                                                  ============  ============

See notes to consolidated financial statements.               (Continued)
</TABLE>


                                       27
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  BALANCE  SHEETS
AS  OF  JUNE  30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
-------------------------------------------------------------------------------------------

LIABILITIES AND STOCKHOLDERS' EQUITY                                  2004          2003
                                                                 ------------  ------------
<S>                                                              <C>           <C>
CURRENT LIABILITIES:
  Accounts payable and accrued expenses                          $    14,823   $    13,734
  Current portion of long-term debt                                    1,145           133
  Funds held for future distribution                                  16,701        17,217
  Income taxes payable                                                   128         1,484
  Accrued taxes, other than income                                     9,289         9,643
  Derivatives                                                          7,303           810
  Other current liabilities                                            3,562         1,421
                                                                 ------------  ------------
      Total current liabilities                                       52,951        44,442
LONG-TERM OBLIGATIONS:
  Long-term debt                                                     162,894       173,197
  Deferred trust revenue                                               2,511         2,917
  Deferred income tax liability                                       19,552        20,376
  Derivatives                                                              -         1,319
  Other long-term obligations                                          8,447         8,311
                                                                 ------------  ------------
      Total liabilities                                              246,355       250,562

  Minority Interest                                                    1,495         1,594
COMMITMENTS AND CONTINGENCIES (Note 14)

STOCKHOLDERS' EQUITY:
  Common stock, par value $1.00; 2,000 shares authorized;
    730 shares issued and outstanding                                    730           730
  Class A non-voting common stock, no par value; 100
    shares authorized; 68 and 46 shares issued and outstanding         8,027         5,092
  Additional paid-in capital                                           5,503         5,503
  Retained earnings                                                   48,200        45,150
  Treasury stock and notes receivable arising from
    issuance of common stock                                         (14,954)      (11,824)
  Deferred compensation on restricted stock                           (1,887)            -
  Accumulated other comprehensive loss                                (3,257)         (973)
                                                                 ------------  ------------
      Total stockholders' equity                                      42,362        43,678
                                                                 ------------  ------------
TOTAL                                                            $   290,212   $   295,834
                                                                 ============  ============
See notes to consolidated financial statements.
</TABLE>


                                       28
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  OPERATIONS
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
------------------------------------------------------------------------------------------------------------------
                                                                                  2004       2003         2002
                                                                             -----------  -----------  -----------
<S>                                                                          <C>          <C>          <C>
REVENUES:
  Oil and gas sales                                                          $   57,203   $   51,410   $   38,939
  Gas aggregation and pipeline sales                                             60,819       60,483       41,209
  Well operations and service revenues                                            5,229        5,498        5,490
  Other                                                                             122           35          504
                                                                             -----------  -----------  -----------
                                                                                123,373      117,426       86,142
                                                                             -----------  -----------  -----------
COSTS AND EXPENSES:
  Field operating expenses                                                       11,452       10,128       10,916
  Gas aggregation and pipeline cost of sales                                     56,059       53,693       37,489
  General and administrative                                                     15,573       15,437       17,360
  Taxes, other than income                                                        4,170        3,287        2,175
  Depletion and depreciation of oil and gas properties                           13,300       12,140       12,362
  Depreciation of pipelines, other property and equipment                         4,190        4,294        2,934
  Exploration and impairment                                                     10,796       11,729       27,694
  (Gain) loss on sale of assets                                                  (8,289)         433         (319)
                                                                             -----------  -----------  -----------
                                                                                107,251      111,141      110,611
                                                                             -----------  -----------  -----------
      Income (loss) from operations                                              16,122        6,285      (24,469)
                                                                             -----------  -----------  -----------
OTHER (INCOME) AND EXPENSE:
  Interest expense                                                               15,069       16,383       19,671
  Interest income and other                                                       1,656      (25,848)      (1,135)
                                                                             -----------  -----------  -----------
                                                                                 16,725       (9,465)      18,536
                                                                             -----------  -----------  -----------
Income (loss) before income taxes and minority interest                            (603)      15,750      (43,005)
Income tax expense (benefit)                                                     (4,722)       6,073      (16,822)
                                                                             -----------  -----------  -----------
Income (loss) before minority interest                                            4,119        9,677      (26,183)
Minority interest                                                                   176          240            3
                                                                             -----------  -----------  -----------
Income (loss) before cumulative effect of change in accounting principle:         4,295        9,917      (26,180)
  Change in accounting principle, net of tax                                          -          (73)           -
                                                                             -----------  -----------  -----------
NET INCOME (LOSS)                                                            $    4,295   $    9,844   $  (26,180)
                                                                             ===========  ===========  ===========
Earnings (loss) per common share, basic:
  Income (loss) before change in accounting principle                        $     6.62   $    15.23   $   (39.80)
  Change in accounting principle, net of tax                                          -        (0.11)           -
                                                                             -----------  -----------  -----------
  Basic earnings (loss) per common share                                     $     6.62   $    15.12   $   (39.80)
                                                                             ==========  ============  ===========
Earnings (loss) per common share, diluted:
  Income (loss) before change in accounting principle                        $     6.52   $    14.90   $   (39.80)
  Change in accounting principle, net of tax                                          -        (0.11)           -
                                                                             -----------  -----------  -----------
  Diluted earnings (loss) per common share                                   $     6.52   $   14.79   $    (39.80)
                                                                             ==========  ============  ===========

See notes to consolidated financial statements.
</TABLE>


                                       29
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  OPERATIONS
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS  IN  THOUSANDS)
------------------------------------------------------------------------------------------------------------------------------
                                                                                                                     Notes
                                                    Class A    Restricted   Additional                             Received/
                                           Common    Common     Class A       Paid-In     Retained    Treasury    Issuance of
                                            Stock    Stock       Stock        Capital     Earnings     Stock         Stock
                                           -------  --------  ------------  -----------  ----------  ----------  -------------
<S>                                        <C>      <C>       <C>           <C>          <C>         <C>         <C>
Balance, June 30, 2001                     $   730  $  3,732  $         -   $     5,503  $  63,653   $  (8,204)  $     (1,089)
                                           =======  ========  ============  ===========  ==========  ==========  =============
  Comprehensive loss                                                                       (26,180)
  Dividends                                                                                 (1,051)
  Class A stock issued for services                    1,360
  Purchase of treasury stock - common                                                                   (1,262)
  Purchase of treasury stock - Class A                                                                    (571)
  Reduction of notes receivable                                                                                           700
                                           -------  --------  ------------  -----------  ----------  ----------  -------------
Balance, June 30, 2002                     $   730  $  5,092  $         -   $     5,503  $  36,422   $ (10,037)  $       (389)
                                           =======  ========  ============  ===========  ==========  ==========  =============
  Comprehensive income (loss)                                                                9,844
  Dividends                                                                                 (1,116)
  Purchase of stock - common                                                                              (854)
  Purchase of stock - Class A                                                                             (639)
  Reduction of notes receivable                                                                                            95
                                           -------  --------  ------------  -----------  ----------  ----------  -------------
Balance, June 30, 2003                     $   730  $  5,092  $         -   $     5,503  $  45,150   $ (11,530)  $       (294)
                                           =======  ========  ============  ===========  ==========  ==========  =============
  Comprehensive income (loss)                                                                4,295
  Dividends                                                                                 (1,245)
  Issuance of stock - Class A                            554        2,410
  Restricted stock amortization
  Purchase of stock - common                                                                            (1,473)
  Purchase of stock - Class A                                         (29)                                (336)
  Shares subject to mandatory redemption
     upon adoption of SFAS No. 150                                                                      (1,383)
  Reduction of notes receivable                                                                                            62
                                           -------  --------  ------------  -----------  ----------  ----------  -------------
Balance, June 30, 2004                     $   730  $  5,646  $     2,381   $     5,503  $  48,200   $ (14,722)  $       (232)
                                           =======  ========  ============  ===========  ==========  ==========  =============



                                                            Accum. Other         Total
                                              Deferred      Comprehensive    Stockholders'
                                            Compensation    Income (Loss)       Equity
                                           --------------  ---------------  ---------------
<S>                                        <C>             <C>              <C>
Balance, June 30, 2001                     $           -   $          501   $       64,826
                                           ==============  ===============  ===============
  Comprehensive loss                                                 (678)         (26,858)
  Dividends                                                                         (1,051)
  Class A stock issued for services                                                  1,360
  Purchase of treasury stock - common                                               (1,262)
  Purchase of treasury stock - Class A                                                (571)
  Reduction of notes receivable                                                        700
                                           --------------  ---------------  ---------------
Balance, June 30, 2002                     $           -   $         (177)  $       37,144
                                           ==============  ===============  ===============
  Comprehensive income (loss)                                        (796)           9,048
  Dividends                                                                         (1,116)
  Purchase of stock - common                                                          (854)
  Purchase of stock - Class A                                                         (639)
  Reduction of notes receivable                                                         95
                                           --------------  ---------------  ---------------
Balance, June 30, 2003                     $           -   $         (973)  $       43,678
                                           ==============  ===============  ===============
  Comprehensive income (loss)                                      (2,284)           2,011
  Dividends                                                                         (1,245)
  Issuance of stock - Class A                     (2,133)                              831
  Restricted stock amortization                      246                               246
  Purchase of stock - common                                                        (1,473)
  Purchase of stock - Class A                                                         (365)
  Shares subject to mandatory redemption
     upon adoption of SFAS No. 150                                                  (1,383)
  Reduction of notes receivable                                                         62
                                           --------------  ---------------  ---------------
Balance, June 30, 2004                     $      (1,887)  $       (3,257)  $       42,362
                                           ==============  ===============  ===============
</TABLE>


                                       30
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS IN THOUSANDS)
-----------------------------------------------------------------------------------------------------------
                                                                              2004       2003       2002
                                                                            ---------  ---------  ---------
<S>                                                                         <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)                                                           $  4,295   $  9,844   $(26,180)
Adjustments to reconcile net income (loss) to net cash provided (used) by
  operating activities:
    Depletion, depreciation and amortization                                  17,490     16,434     16,031
    (Gain) loss on sale of assets                                             (8,289)       433       (319)
    Gain on redemption of senior bonds                                          (513)   (23,672)         -
    Deferred income taxes                                                     (2,870)    12,685    (12,492)
    Exploration and impairment                                                10,730     11,508     27,227
    Other, net                                                                   481      2,636      2,322
                                                                            ---------  ---------  ---------
                                                                              21,324     29,868      6,589
Changes in assets and liabilities:
  Accounts receivable                                                          2,149     (4,817)     3,187
  Income taxes receivable                                                          -          -     (2,066)
  Income taxes payable                                                        (1,357)     3,081          -
  Prepaid and other assets                                                      (165)    (1,560)    (1,030)
  Accounts payable and accrued expenses                                          521       (627)    (2,218)
  Funds held for future distributions                                           (516)     5,803     (3,253)
  Other                                                                           52     (8,522)   (23,405)
                                                                            ---------  ---------  ---------
    Net cash provided (used) by operating activities                          22,008     23,226    (22,196)

CASH FLOWS FROM INVESTING ACTIVITIES
  Expenditures for property, plant and equipment                             (21,910)   (37,632)   (38,294)
  Proceeds from sale of assets                                                10,844      3,532        704
  Notes receivable and other                                                   1,560      1,259         86
                                                                            ---------  ---------  ---------
    Net cash used by investing activities from operations                     (9,506)   (32,841)   (37,504)
 CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds from long-term debt                                                67,281     72,635          -
  Principal payment on long-term debt                                        (76,005)   (73,434)      (145)
  Proceeds from issuance of stock                                                257          -          -
  Purchase of treasury stock and other financing activities                   (1,811)    (1,447)    (1,663)
  Dividends paid                                                              (1,234)    (1,083)    (1,053)
                                                                            ---------  ---------  ---------
    Net cash used by financing activities from operations                    (11,512)    (3,329)    (2,861)
                                                                            ---------  ---------  ---------
    Net (decrease) increase in cash and cash equivalents                         990    (12,944)   (62,561)
    Cash and cash equivalents, beginning of period                             4,831     17,775     80,336
                                                                            ---------  ---------  ---------
Cash and cash equivalents, end of period                                    $  5,821   $  4,831   $ 17,775
                                                                            =========  =========  =========

See notes to consolidated financial statements.
</TABLE>


                                       31
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA
CONSOLIDATED  STATEMENTS  OF  COMPREHENSIVE  INCOME  (LOSS)
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS IN THOUSANDS)
-------------------------------------------------------------------------------

                                                    2004      2003      2002
                                                  --------  --------  ---------
<S>                                               <C>       <C>       <C>
Net income (loss)                                 $ 4,295   $ 9,844   $(26,180)
Other comprehensive income (loss), net of tax:
  Foreign currency translation adjustment:
    Current period change                             755       854      1,627
  Marketable securities:
    Unrealized loss                                     -        (5)      (102)
    Reclassification to earnings                        -       (25)        (4)
  Oil and gas derivatives:
    Net cumulative effect adjustment                    -         -          -
    Current period transactions                    (2,775)   (2,351)     1,999
    Reclassification to earnings                     (264)      731     (4,198)
                                                  --------  --------  ---------
Other comprehensive loss, net of tax               (2,284)     (796)      (678)
                                                  --------  --------  ---------
Comprehensive income (loss)                       $ 2,011   $ 9,048   $(26,858)
                                                  ========  ========  =========

See notes to consolidated financial statements.
</TABLE>


                                       32
<PAGE>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002
--------------------------------------------------------------------------------

1.   NATURE OF ORGANIZATION

     Energy  Corporation  of  America  (the  "Company")  was formed in June 1993
     through  an  exchange  of  shares  with  the common stockholders of Eastern
     American  Energy  Corporation  ("Eastern  American").  The  Company  is  an
     independent  energy company. All references to the "Company" include Energy
     Corporation  of  America  and  its consolidated subsidiaries. The Company's
     industry  segments  are  discussed  at  Note  16.


2.   SUMMARY  OF  SIGNIFICANT  ACCOUNTING  POLICIES

     The  following is a summary of the significant accounting policies followed
     by  the  Company.

     Principles of Consolidation - The consolidated financial statements include
     ---------------------------
     the accounts of the Company and its subsidiaries. Investments in affiliates
     in which the Company owns greater than 50% are consolidated. Investments in
     which  the  Company  owns  from  20% to 50% are accounted for by the equity
     method  if  the Company has the ability to exert significant influence over
     the  investee,  but  does  not  otherwise  have  the  ability  to  control.
     Investments  in  less than 20% owned affiliates and affiliates in which the
     Company  does not exhibit significant influence are accounted for under the
     cost  method.  The  Company  has  investments  in  oil  and  gas  limited
     partnerships  and joint ventures and has recognized its proportionate share
     of  these  entities'  revenues,  expenses,  assets  and  liabilities.  All
     significant  intercompany  transactions  have  been  eliminated  in
     consolidation.

     Cash  and  Cash  Equivalents - Cash and cash equivalents include short-term
     ----------------------------
     investments  maturing  in  three  months  or  less  from the date acquired.

     Property,  Plant  and  Equipment - Oil and gas properties are accounted for
     --------------------------------
     using  the  successful  efforts  method  of  accounting. Under this method,
     certain  expenditures such as exploratory geological and geophysical costs,
     exploratory  dry  hole  costs,  delay  rentals  and  other costs related to
     exploration  are  recognized  currently as expenses. All direct and certain
     indirect  costs  relating  to  property acquisition, successful exploratory
     wells,  development  costs,  and  support  equipment  and  facilities  are
     capitalized.  The Company computes depletion, depreciation and amortization
     of capitalized oil and gas property costs on the units-of-production method
     using  proved  developed  reserves.  Direct  production  costs,  production
     overhead  and other costs are charged against income as incurred. Gains and
     losses  on  the  sale  of  oil  and  gas  property  interests are generally
     recognized  in  income.

     Other  property,  equipment, pipelines and buildings are stated at cost and
     are  depreciated using straight-line and accelerated methods over estimated
     useful  lives  ranging  from  three  to  forty  years.

     Repairs  and  maintenance  costs  are  charged  against income as incurred;
     significant  renewals  and betterments are capitalized. Gains and losses on
     dispositions of property, equipment, pipelines and buildings are recognized
     as  income.


                                       33
<PAGE>
     At  June  30  property,  plant and equipment consisted of the following (in
thousands):

<TABLE>
<CAPTION>
                                                               2004        2003
                                                            ----------  ----------
<S>                                                         <C>         <C>
Oil and gas properties                                      $ 345,556   $ 337,904
Pipelines                                                      21,856      20,594
Other property and equipment                                   22,825      23,537
                                                            ----------  ----------
                                                              390,237     382,035
Less accumulated depletion, depreciation and amortization    (143,846)   (128,765)
                                                            ----------  ----------
Net property, plant and equipment                           $ 246,391   $ 253,270
                                                            ==========  ==========
</TABLE>

     Long-Lived  Assets  -  Statement of Financial Accounting Standards ("SFAS")
     ------------------
     No.  144,  "Accounting  for  the  Impairment  of  Long-Lived Assets and for
     Long-Lived  Assets  to  be  Disposed  Of", requires all companies to assess
     long-lived assets and assets to be disposed of for impairment. For the year
     ended  June  30,  2004,  the impairment recognized by the Company primarily
     consists of oil and gas property of $2.4 million and other property of $1.1
     million. The other property is primarily related to the sale of an interest
     in  a drilling rig held with Breitburn Energy Company L.P. ("BECLP") and is
     discussed  further  in  Note 10. During the fiscal year ended June 30, 2003
     the  Company recognized impairment of oil and gas property of $3.1 million.

     Deferred  Financing  Costs  -  Certain  legal,  underwriting fees and other
     --------------------------
     direct expenses associated with the issuance of credit agreements, lines of
     credit  and  other  financing  transactions  have  been  capitalized. These
     financing  costs  are  being  amortized over the term of the related credit
     agreement.

     Foreign  Currency  Translation  -  The  translation  of  applicable foreign
     ------------------------------
     currencies  into  U.S.  dollars  is  performed  for  accounts using current
     exchange  rates  in  effect  at  the  balance  sheet  date. The translation
     adjustment  is  included  in  stockholders'  equity as a component of other
     comprehensive  income.

     Income  Taxes  -  Deferred  income  taxes  reflect the impact of "temporary
     -------------
     differences"  between  assets  and  liabilities  recognized  for  financial
     reporting  purposes  and  such  amounts  as  measured  by  tax  laws. These
     temporary  differences  are  determined  in  accordance  with SFAS No. 109,
     "Accounting For Income Taxes". A valuation allowance is established for any
     portion of a deferred tax asset for which it is more likely than not that a
     tax  benefit  will  not  be  realized.

     Deferred  Trust  Revenue-  In  1993,  the Company sold working interests in
     ------------------------
     certain  Appalachian gas properties in connection with the formation of the
     Eastern  American Natural Gas Trust ("the Royalty Trust"). A portion of the
     proceeds  from  the  sale of these interests, representing term net profits
     interest,  was  accounted for as a production payment and was classified as
     deferred  trust  revenue.  The deferred revenue is recognized as production
     occurs  for  the  term  properties.

     Revenues  and  Gas  Costs - Oil and gas sales, and aggregation and pipeline
     -------------------------
     revenues are recognized as income when the oil or gas is produced and sold.
     Monthly,  the Company makes estimates of the amount of production delivered
     to  the  purchaser  and  the  price  to  be  received. The Company uses its
     knowledge  of  properties,  historical  performance,  NYMEX  and local spot
     market prices and other factors as the basis for these estimates. Gas costs
     are  expensed  as  incurred.

     Stock  Compensation  -  As  permitted  under  SFAS No. 123, "Accounting for
     -------------------
     Stock-Based  Compensation",  the Company has elected to continue to measure
     compensation  costs  for  stock-based employee compensation plans using the
     intrinsic value method as prescribed by Accounting Principles Board Opinion
     No.  25,  "Accounting  for  Stock  Issued  to  Employees".  Stock


                                       34
<PAGE>
     compensation  expense  of  $0.5  million and $0.9 million was recognized in
     June 30, 2004 and June 30, 2002, respectively, with no expense recorded for
     the  year  ended  June  30,  2003.


     Use  of  Estimates  - The preparation of financial statements in conformity
     ------------------
     with  generally  accepted  accounting  principles  in  the United States of
     America  requires  management to make estimates and assumptions that affect
     the reported amounts of assets and liabilities and disclosure of contingent
     assets  and  liabilities  at  the  date of the financial statements and the
     reported  amounts  of  revenues  and  expenses during the reporting period.
     Actual  results  could  differ  from  those  estimates.

     The  Company's  financial  statements  are based on a number of significant
     estimates including oil and gas reserve quantities, which are the basis for
     the  calculation of depletion, depreciation, amortization and impairment of
     oil  and  gas  properties. Management emphasizes that reserve estimates are
     inherently  imprecise.  In  addition, realization of deferred tax assets is
     based  largely  on  estimates  of  future  taxable  income.

     Derivatives  -  In accordance with SFAS No. 133, "Accounting for Derivative
     -----------
     Instruments and Hedging Activities", as amended, all derivative instruments
     are  recorded  as  assets or liabilities in the Company's balance sheet and
     measurement  of  those  instruments  at  its'  estimated  fair  value.  The
     accounting  treatment of changes in fair value is dependent upon whether or
     not a derivative instrument is designated as a hedge and if so, the type of
     hedge.  For  derivatives  designated  as  cash flow hedges, changes in fair
     value are recognized in other comprehensive income; to the extent the hedge
     is  effective,  until  the  hedged  item  is  recognized in earnings. Hedge
     effectiveness  is  measured  monthly  based on the relative changes in fair
     value  between  the  derivative contract and the hedged item over time. Any
     change in fair value resulting from ineffectiveness and any derivatives not
     qualifying as hedges are recognized immediately in earnings.

     Accumulated  Other  Comprehensive  Loss-  At  June  30  accumulated  other
     ---------------------------------------
     comprehensive  loss  consisted  of  the  following  (in  thousands):

                                                      2004        2003
                                                    --------    --------
          Foreign currency translation              $ 1,122     $   367
          Natural gas hedging                        (4,379)     (1,340)
                                                    --------    --------
            Accumulated other comprehensive loss    $(3,257)    $  (973)
                                                    ========    ========

     Concentration  of  Credit  Risk  -  The Company maintains its cash accounts
     -------------------------------
     primarily  with  a  single  bank and invests cash in money market accounts,
     which  the  Company  believes  to have minimal risk. As operator of jointly
     owned  oil  and gas properties, the Company sells oil and gas production to
     numerous  U.S.  oil and gas purchasers, and pays vendors on behalf of joint
     owners  for  oil  and  gas  services.  Both purchasers and joint owners are
     located  primarily in the northeastern United States and Texas. The risk of
     nonpayment  by the purchasers or joint owners is considered minimal and has
     been  considered  in  the  Company's  allowance  for  doubtful  accounts.

     Environmental  Concerns  -  The  Company  is  continually taking actions it
     -----------------------
     believes  necessary  in its operations to ensure conformity with applicable
     federal,  state  and  local environmental regulations. As of June 30, 2004,
     the  Company  has not been fined or cited for any environmental violations,
     which  would  have  a  material  adverse  effect upon capital expenditures,
     operating  results  or  the  competitive  position  of  the  Company.


                                       35
<PAGE>
     Prior  Year Reclassifications - Certain amounts in the financial statements
     -----------------------------
     of  prior  years  have  been  reclassified  to  conform to the current year
     presentation.

     Recent  Accounting Pronouncements - In March 2004, the Emerging Issues Task
     ---------------------------------
     Force  ("EITF") reached a consensus that mineral rights, as defined in EITF
     Issue No. 04-2, "Whether Mineral Rights Are Tangible or Intangible Assets,"
     are  tangible  assets  and  that  they  should  be  removed  as examples of
     intangible  assets  in  SFAS  No. 141, "Business Combinations" and No. 142,
     "Goodwill and Other Intangible Assets." The FASB has recently ratified this
     consensus  and  directed  the  FASB  staff  to  amend SFAS Nos. 141 and 142
     through  the  issuance  of  FASB  Staff Position ("FSP") FAS Nos. 141-1 and
     142-1.  In  addition,  proposed  FSP  142-b confirms that SFAS 142 does not
     change the balance sheet classification or disclosures of mineral rights of
     oil  and  gas producing enterprises. Historically, the Company has included
     the  costs  of  such mineral rights as tangible assets, which is consistent
     with  the  EITF's  consensus. As such, EITF 04-02 and the related FSPs have
     not  affected  the  Company's  consolidated  financial  statements.

     In May 2003 the FASB issued Statement of Financial Accounting Standards No.
     150,  "Accounting for Certain Financial Instruments with Characteristics of
     both Liabilities and Equity". SFAS No. 150 establishes standards for how an
     issuer  classifies  and  measures  certain  financial  instruments  with
     characteristics  of  both  liabilities and equity, and requires instruments
     that  fall  within  the  scope  of  this  pronouncement to be classified as
     liabilities. The Company early adopted SFAS No. 150 at the beginning of the
     fourth quarter of the year ended June 30, 2004. The effect of this adoption
     was  an  increase  to other current liabilities of $0.2 million, other long
     term  obligations  of  $1.2  million  and  a  $1.4  million  decrease  in
     stockholders'  equity.

     Asset  Retirement  Obligations  -  The  Company  accounts  for  its'  asset
     ------------------------------
     retirement  obligations  according  to  SFAS No. 143, "Accounting for Asset
     Retirement  Obligations." SFAS No. 143 provides the accounting requirements
     for retirement obligations associated with tangible long-lived assets. When
     the  liability  is  initially  recorded,  the  entity capitalizes the cost,
     thereby  increasing  the  carrying  amount of the related long-lived asset.
     Over  time,  the  liability  is  accreted,  and  the  capitalized  cost  is
     depreciated  over  the  useful  life  of  the  related  asset.

     For  the  Company,  asset  retirement  obligations  primarily relate to the
     abandonment  of  oil  and  gas  producing  facilities. While assets such as
     pipelines  and  marketing assets may have retirement obligations covered by
     SFAS  No.  143,  certain  of those obligations are not recognized since the
     fair  value  cannot  be  estimated due to the uncertainty of the settlement
     date  of  the  obligation.

     The  initial  application  of this accounting standard by ECA as of July 1,
     2002, resulted in an increase in net plant assets of $0.4 million, an asset
     retirement obligation liability of $0.5 million, and a cumulative effect of
     a  change  in  accounting  principle  of  $0.1  million. Due to a change in
     estimate  by  ECA  in  fiscal year 2003 regarding SFAS No. 143, the initial
     application was changed to an asset retirement obligation liability of $0.7
     million,  a  net  plant  asset  increase  of $0.6 million, and a cumulative
     effect  of  a change in accounting principle of $0.1 million as of June 30,
     2003.


                                       36
<PAGE>
The  following  table  presents  a  reconciliation  of  the beginning and ending
carrying  amounts  of  the  asset  retirement  obligations.

<TABLE>
<CAPTION>
                                                              (IN THOUSANDS)
                                                               2004    2003
                                                              ------  ------
<S>                                                           <C>     <C>

Asset retirement obligation as of the beginning of the year   $ 724   $ 471
    Accretion expense                                            44      33
    Liabilities incurred                                         22     181
    Liabilities settled                                        (175)    (86)
    Change in estimate                                           58     125
                                                              ------  ------
Asset retirement obligation as of the end of the year         $ 673   $ 724
                                                              ======  ======
</TABLE>


     Supplemental  Disclosures of Cash Flow Information - Supplemental cash flow
     --------------------------------------------------
     information for the years ended June 30 is as follows (in thousands):

<TABLE>
<CAPTION>
                                                 2004      2003
                                               --------  --------
<S>                                            <C>       <C>
Cash paid for:
  Interest                                     $15,069   $16,383
  Income taxes                                      25        15
Income taxes refunded                              (38)   (9,809)
Noncash investing and financing activities:
    Dividends declared and unpaid at year end      308       297
</TABLE>


3.   ACQUISITIONS

     The  Company  finalized the purchase of an additional 100-mile long natural
     gas  gathering  system ("System 8000") from Columbia Gas Transmission for a
     purchase  price  of  $1.2  million  during the first quarter of fiscal year
     2005.  System  8000 is located in northeastern West Virginia and is situate
     among  one  of  the  Company's  existing  operating  areas.

     On  February  5, 2003, the Company purchased certain oil and gas properties
     located  in  southern  West  Virginia  for  $5.6  million,  after  certain
     adjustments. The purchase included proved developed producing gas reserves,
     estimated  at  4  Bcf,  90  producing  wells  and  over  30,000  acres.

4.   RISK  MANAGEMENT

     The  Company  periodically  hedges  a portion of its oil and gas production
     through futures and swap agreements. The purpose of the hedge is to provide
     a  measure  of  stability in the volatile environment of oil and gas prices
     and  to  manage  exposure  to  commodity price risk under existing sales or
     purchase  commitments.  All of the Company's price swap agreements in place
     at  June 30, 2004 are designated as cash flow hedges. At June 30, 2004, the
     Company  had  swap  agreements  maturing  from  July 2004 through June 2005
     covering  4,375,000  Mmbtu.  At  June  30,  2004,  the


                                       37
<PAGE>
     Company had recorded a $4.4 million loss in accumulated other comprehensive
     income,  $0.03  million  of  short  term derivative assets, $7.3 million in
     short  term  derivative liabilities and $2.9 million in deferred tax asset.
     At  June  30, 2003, the Company had swap agreements maturing from July 2003
     through June 2005 covering 5,058,000 Mmbtu. As of June 30, 2003 the Company
     had recorded a $1.3 million loss in accumulated other comprehensive income,
     $0.8  million  in  short  term derivative liabilities, $1.3 million in long
     term  derivative  liabilities,  and  $0.8  million  in  deferred tax asset.

     For  the  year  ended  June  30,  2004 the Company recognized a net loss in
     revenues  on  its  natural  gas hedging activities of $0.4 million. For the
     year  ended June 30, 2003, the Company recognized a net loss in revenues on
     its  natural  gas hedging activities of $1.2 million and a net gain of $6.7
     million  for  the year ended June 30, 2002. The estimated net amount of the
     existing  losses  within other comprehensive income that are expected to be
     reclassified  into  earnings within the next twelve months is approximately
     $4.4  million.

     5.     DEBT

     Long-Term  Debt  - At June 30 long-term debt consisted of the following (in
     ---------------
     thousands):

<TABLE>
<CAPTION>
                                                                      2004       2003
                                                                    ---------  ---------
<S>                                                                 <C>        <C>
ECA senior subordinated notes, interest at 9.5% payable
  semi-annually, due May 15, 2007                                   $126,033   $132,073
Revolving credit agreements, variable rates                           37,109     40,227
Installment notes payable, at imputed interest rates ranging from
  from 8.0% to 9.5%                                                      897      1,030
                                                                    ---------  ---------
                                                                     164,039    173,330
Less current portion                                                  (1,145)      (133)
                                                                    ---------  ---------
                                                                    $162,894   $173,197
                                                                    =========  =========
</TABLE>

     Scheduled  maturities  of the Company's long-term debt at June 30, 2004 for
each  of  the  next  five  years  and  thereafter are as follows (in thousands):

<TABLE>
<CAPTION>
<S>                                     <C>
2005                                    $ 35,213
2006                                         213
2007                                      92,142
2008                                         100
2009                                      36,209
 Thereafter                                  484
                                        --------
 Total payments                          164,361
 Less:  imputed interest                     322
                                        --------
 Present value of scheduled maturities  $164,039
                                        ========
</TABLE>

     Senior  Subordinated  Notes  -The  Company  has 9 1/2 % Senior Subordinated
     ---------------------------
     Notes  ("Notes")  that are due May 15, 2007. The agreement contains certain
     restrictions  and  conditions  among which are limitations on indebtedness,
     dividends  and  investments,  and  certain  interest  coverage  ratio
     requirements.


                                       38
<PAGE>
     The  Company  purchased $6.04 million of its Notes during the twelve months
     ended June 30, 2004, $2.04 million in privately negotiated transactions and
     $4.0  million  pursuant  to an Asset Sale Offer as defined in the Indenture
     for the Notes that resulted in a gain of $0.5 million which was included in
     interest  income  and  other.

     The Company purchased $34 million of the Notes on July 29, 2004 pursuant to
     an  Asset Sale Offer as defined in the Indenture for the Notes. The Company
     classified  this debt as long term at June 30, 2004 as a result of entering
     into  an  amended  and  restated credit agreement in place that allowed the
     Company to refinance the debt on a long term basis. See Note 18 for further
     discussion.

     For  the year ended June 30, 2003 the Company purchased approximately $65.6
     million  of  the  Notes  that resulted in a gain of $23.7 million which was
     included  in  interest  income  and  other.

     Revolving  Credit  and Term Loan -As previously reported, on July 10, 2002,
     --------------------------------
     the  Company  entered  into  a  $50 million revolving Credit Agreement with
     Foothill  Capital Corporation, now Wells Fargo Foothill, Inc. ("Foothill").
     The  Company  and Foothill have entered into an Amended and Restated Credit
     Agreement  dated  June  10,  2004  (the  "Restated  Credit Agreement"). The
     Restated  Credit  Agreement  provides  for the $50 million revolving credit
     facility  to be extended and for the Company to be provided with additional
     credit  in  the  form  of  a  single advance term loan in the amount of $50
     million.  The  term loan contains requirements for principal payments of $1
     million  each  at  July 10, 2005, 2006 and 2007, with the remaining balance
     due  on  July 10, 2008. Depending on the Company's level of borrowing under
     the  Restated Credit Agreement, the applicable interest rates for base rate
     loans  are  based  on  Wells  Fargo's  prime  rate plus 0.25% to 0.75%. The
     Company  has  the  ability under the Restated Credit Agreement to designate
     certain  loans as Libor Rate Loans at interest rates based upon the rate at
     which  dollar  deposits  are offered to major banks in the London interbank
     market  plus  2.25% to 2.75%. The Restated Credit Agreement expires on July
     10,  2008.

     The  obligations under the Restated Credit Agreement are secured by certain
     of  the  existing  proved  producing oil and gas assets of the Company. The
     Restated Credit Agreement, among other things, restricts the ability of the
     Company  and  its subsidiaries to incur new debt, grant additional security
     interests  in  its  collateral,  engage in certain merger or reorganization
     activities,  or  dispose of certain assets. As of September 23, 2004, there
     are  $50.0  million  in  outstanding borrowings under the term loan and $15
     million  in  outstanding  borrowings  under  the  revolving  loan.

     Other  Credit  Facilities  - The Company has an unsecured revolving line of
     -------------------------
     credit  totaling $3.0 million with a financial institution with an interest
     rate  of  prime  plus 0.25%, which reduces by $1.0 million in November 2004
     and  expires  on June 30, 2005. As of June 30, 2004, there was $1.0 million
     outstanding under the line of credit and $1.8 million was committed through
     letters  of credit. As of June 30, 2003, there was $1.0 million outstanding
     under  the  line  of  credit.

     Other  Notes - In December 2000 the Company assumed a note which stipulated
     ------------
     that the Company will pay consecutive equal monthly payments with the first
     scheduled  payment  to  be  made by the Company on January 15, 2000 and the
     final  scheduled  payment  due  on  April 15, 2014. As of June 30, 2004 and
     2003,  the  balance  due  was  $1.0  million  and  $1.1  respectively.

     The  Company purchased certain pipelines during 1998 constituting a natural
     gas  gathering  system  in the State of West Virginia. The Company paid the
     seller  $1.2  million for the facilities. In accordance with the agreement,
     the Company paid $0.3 million at closing with the balance due to the seller
     in  one  hundred  consecutive equal monthly installments beginning in March
     1998.  As of June 30, 2004 and 2003, the balance due to the seller was $0.2
     and  $0.3  million  respectively.


                                       39
<PAGE>
6.   INCOME  TAXES

     The  following  table  summarizes  components  of  the  Company's provision
     (benefit)  for  income  taxes  for  the years ended June 30 (in thousands):

<TABLE>
<CAPTION>
                                                2004      2003      2002
                                              --------  --------  ---------
<S>                                           <C>       <C>       <C>
Current:
  Federal                                     $(1,523)  $(6,610)  $ (3,436)
  State                                          (329)       (2)     1,385
                                              --------  --------  ---------
  Total current                                (1,852)   (6,612)    (2,051)
                                              --------  --------  ---------
Deferred:
  Federal                                      (2,116)   11,502    (13,381)
  State                                          (754)    1,183     (1,390)
                                              --------  --------  ---------
  Total deferred                               (2,870)   12,685    (14,771)
                                              --------  --------  ---------
  Total provision (benefit) for income taxes  $(4,722)  $ 6,073   $(16,822)
                                              ========  ========  =========
</TABLE>


     A  reconciliation  of  the  provision  for  income  taxes  computed  at the
statutory  rate  to  the provision for income taxes as shown in the consolidated
statements  of  operations  for  the years ended June 30 is summarized below (in
thousands):

<TABLE>
<CAPTION>
                                                         2004     2003      2002
                                                       --------  -------  ---------
<S>                                                    <C>       <C>      <C>
Tax provision (benefit) at the federal statutory rate  $  (150)  $5,513   $(15,051)
State taxes, net of federal tax effects                    (25)     663     (2,516)
Effect of rate change                                        -       12        103
Change in valuation allowance on federal, foreign
and state deferred tax assets, net of federal effect         -        -     (2,048)
Change in tax contingency                               (4,514)       -          -
Other, net                                                 (33)    (115)     2,690
                                                       --------  -------  ---------
Total provision (benefit) for income taxes             $(4,722)  $6,073   $(16,822)
                                                       ========  =======  =========
</TABLE>


                                       40
<PAGE>
Components of the Company's deferred tax assets and liabilities, as of June 30
are as follows (in thousands):

<TABLE>
<CAPTION>
                                        2004       2003
                                      ---------  ---------
<S>                                   <C>        <C>
Deferred tax assets:
  Royalty Trust agreements            $  4,087   $  4,640
  Tax credits and carryforwards          7,236      7,795
  Other                                  3,294      2,512
                                      ---------  ---------
    Total deferred tax assets           14,617     14,947
                                      ---------  ---------
Deferred tax liabilities:
  Property, plant and equipment        (31,770)   (28,920)
  Other liabilities                       (312)    (6,362)
                                      ---------  ---------
    Total deferred tax liabilities     (32,082)   (35,282)
                                      ---------  ---------

Net deferred tax liability            $(17,465)  $(20,335)
                                      =========  =========

Current deferred tax asset            $  2,087   $     41
Long-term deferred tax liability       (19,552)   (20,376)
                                      ---------  ---------
Net deferred tax liability            $(17,465)  $(20,335)
                                      =========  =========
</TABLE>

At June 30 the Company has the following federal and state tax credits and
carryforwards (in thousands):

<TABLE>
<CAPTION>
                                                 2004                 2003
                                                     Year of              Year of
                                           Amount   Expiration  Amount   Expiration
                                           -------  ----------  -------  ----------
<S>                                        <C>      <C>         <C>      <C>
AMT tax credits                            $ 3,591  None        $ 4,444  None
Charitable contribution carryforwards          166   2007-2008        3   2007-2008
                                           -------              -------
Total federal credits and carryforwards    $ 3,757              $ 4,447
                                           =======              =======

State net operating loss carryforwards     $ 3,479   2005-2022  $ 3,348   2005-2022
                                           -------              -------
Total state carryforwards                  $ 3,479              $ 3,348
                                           =======              =======

Total federal and state carryforwards      $ 7,236              $ 7,795
                                           =======              =======
</TABLE>

     At  June  30, 2001, the Company had West Virginia state tax credits of $3.7
     million.  The  Company  was eligible for relocation incentives taken in the
     form  of  tax  credits from West Virginia. The incentive amounts were based
     upon investments made and jobs created in that state. Tax credits generated
     by  the  Company  were  used  primarily to offset the payment of severance,
     property  and state income taxes. Based on the then existing future taxable
     temporary  differences  and  projections of future West Virginia severance,
     property  and  state  income  taxes,  management  had  provided a valuation
     allowance  of  $3.2  million  for that portion of the credits that were not
     expected  to  be  utilized.  At  June 30, 2003 the Company had utilized the
     entire  $3.7  million  of WV state tax credits and had reversed the related
     $3.2  million  valuation  allowance.

     During  2004,  the  Company  utilized $0.9 million in AMT Credits. The $3.6
     million  in  remaining  AMT  credits  may  be  utilized  in future periods.


                                       41
<PAGE>
     In  March  2004,  the  U.S.  Internal  Revenue Service ("IRS") notified the
     Company that it was initiating an audit of the Company's federal income tax
     return for the tax year ending June 30, 2002. The IRS is also reviewing the
     refund  claim  filed  by  the Company due to the amended federal income tax
     return  for the tax year ending June 30, 1999. The Company has not received
     any  notices  of  proposed  adjustments and believes that it has adequately
     provided  for  any potential tax liability that may be assessed by the IRS.
     In  connection  with the evaluation of contingencies, the Company continues
     to  perform  periodic  reviews.  During  2004,  the  Company  adjusted  the
     contingency  balance  for  items  that  are closed or no longer applicable.

7.   EMPLOYEE  BENEFIT  PLANS

     The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock
     Plan (the "Plan") for the stated purpose of expanding and improving profits
     and  prosperity  and  to assist the Company in attracting and retaining key
     personnel.  The  Plan  is noncontributory, and its continuance from year to
     year  is  at  the  discretion  of the Board of Directors. The annual profit
     sharing  pool is based on calculations set forth in the Plan. Generally, to
     be  eligible  to  participate,  an  employee  must  have  been continuously
     employed for two or more years; however, employees with less than two years
     of  employment  may  participate  under  certain circumstances. The Company
     recognized  $1.7  million and $2.4 million of profit sharing expense during
     the  years  ended  June  30,  2004  and 2003, respectively, while no profit
     sharing  expense  was  recognized  for  the  year  ended  June  30,  2002.

     The Company sponsors a Section 401(k) plan covering all full-time employees
     who wish to participate. The Company's contributions, which are principally
     based  on  a  percentage of the employee contributions, and charged against
     income  as incurred, totaled $0.29 million, $0.27 million and $0.25 million
     for  the  years  ended  June  30,  2004,  2003,  and  2002.

8.   CAPITAL  STOCK

     Voting  Common  Stock-  In  May 1995, the Company was reincorporated in the
     ---------------------
     State  of  West Virginia. As part of this reincorporation, each outstanding
     share of then existing no-par value common stock was converted to one share
     of  $1  par  value  common  stock.

     Pursuant  to  an Agreement dated December 28, 1998, the Company is required
     to purchase all shares owned by Kenneth W. Brill upon notice by Mr. Brill's
     estate or promptly after the passage of two years from Mr. Brill's death if
     the  estate  does  not sooner tender the shares. The Company entered into a
     repurchase  agreement  on January 21, 2004 with the KWB Trust to define the
     purchase  price  and  establish  the conditions for the repurchase of stock
     owned  by  the  Kenneth  W.  Brill,  estate.  The  agreement  outlines  the
     repurchase  of  49,110  shares  of  stock  by  the Company or through third
     parties,  at  an  anticipated  value of approximately $3.7 million over the
     next five years, and provides for payments in twenty quarterly installments
     on  the  majority of the shares to be repurchased. The repurchase of shares
     is  subject  to certain restrictions in the Company's credit agreements. On
     June  30,  2004,  the  Company's  remaining repurchase obligation under the
     Agreement  is approximately $2.9 million. Upon adoption of SFAS No. 150, as
     described  in  Note 2, $1.4 million of the obligation was reclassified as a
     liability  and  the  remaining  $1.5  million  is included in stockholders'
     equity  as  third  parties  have  agreed  to  purchase  such  amount.

     Class  A  Non-Voting Common Stock - In August 1998, the Company amended its
     ---------------------------------
     articles  of incorporation authorizing the issuance of up to 100,000 shares
     of  Class  A  non-voting  common  stock.

     During  October,  2003, ECA offered its employees that were participants in
     the  2003 Profit Sharing program, the opportunity to purchase Class A stock


                                       42
<PAGE>
     having certain restrictions. Employees were awarded the right to purchase a
     specified number of shares, with the restrictions expiring over a specified
     period  of  time.  As a result of this program, 16,850 shares of restricted
     stock  were  issued  for  $15  per  share vesting over five years. Deferred
     compensation  was  recognized  based  on  the  fair  value  of the stock at
     issuance  and  is  being  amortized  over  the  vesting period. The Company
     repurchased  201  shares of the restricted stock during the year ended June
     30,  2004.

     Treasury Stock - At June 30, 2004, the Company had 126,613 shares of voting
     --------------
     common stock in treasury, carried at cost. The Company purchased 15,367 and
     6,262  shares  of  voting common stock during the years ended June 30, 2004
     and  2003, respectively. At June 30, 2004, the Company had 21,202 shares of
     non-voting  Class  A  stock  in  treasury,  carried  at  cost.  The Company
     purchased  2,349  and  4,473  shares of non-voting Class A stock during the
     years  ended  June  30,  2004  and  2003.

     Stock  Plans  -  During fiscal 1999, the Company created an incentive stock
     ------------
     purchase  agreement,  primarily for outside Directors. Under the agreement,
     options  to  purchase  voting  common  stock were granted at $75 per share,
     based  on the fair market value as determined by the Board of Directors and
     are  exercisable  based  on  the  following  schedule:

                                           Number of
            Exercise Period                 Shares
     -------------------------------------  ---------

     January 1, 2000 to December 31, 2004     10,002
     January 1, 2001 to December 31, 2005      9,996
                                           ---------
                                              19,998
                                           =========

     No  options  were  exercised for either of the years ended June 30, 2004 or
     2003.  Therefore,  as  of  June  30,  2004,  all the remaining options were
     exercisable.  Fair value of the options at the grant dates, as estimated by
     management,  was  nominal.


9.   EARNINGS  PER  SHARE

     In  accordance  with SFAS No. 128, "Earnings Per Share," basic earnings per
     share has been computed based upon the weighted average shares outstanding.
     Diluted  earnings  per  share  gives  effect  to outstanding stock options.


                                       43
<PAGE>
A reconciliation of the components of basic and diluted net income (loss) per
common share for the years ended June 30 is as follows:

<TABLE>
<CAPTION>
                                                2004      2003       2002
                                              --------  ---------  ---------
<S>                                           <C>       <C>        <C>
Income (loss) before cumulative effect of
  change in accounting principle              $  4,295  $  9,917   $(26,180)
Change in accounting principle, net of tax           -       (73)         -
                                              ------------------------------
Net income (loss)                             $  4,295  $  9,844   $(26,180)
----------------------------------------------------------------------------

Weighted average common shares:
          Basic                                648,835   651,205    657,707
          Diluted                              658,345   665,471    657,707
----------------------------------------------------------------------------

Basic net income (loss) per common share:
Income (loss) from operations before
  extraordinary items                         $   6.62  $  15.23   $ (39.80)
Change in accounting principle, net of tax           -     (0.11)         -
----------------------------------------------------------------------------
Basic net income (loss) per common share      $   6.62  $  15.12   $ (39.80)
----------------------------------------------------------------------------

Diluted net income (loss) per common share:
Income (loss) from operations before
  extraordinary items                         $   6.52  $  14.90   $ (39.80)
Change in accounting principle, net of tax           -     (0.11)         -
----------------------------------------------------------------------------
Diluted net income (loss) per common share    $   6.52  $  14.79   $ (39.80)
----------------------------------------------------------------------------
</TABLE>

     For  fiscal  year  2002  the effect of 14,226 shares related to outstanding
     stock  options were not included in the computation of diluted net loss per
     share  because  to  do  so  would  have  been  antidilutive

10.  UNCONSOLIDATED  AFFILIATE

     The  Company  owned a 25.35% members' interest in Breitburn Energy Company,
     LLC  ("BEC").  The  Company's investment in BEC was accounted for under the
     equity  method. Although BEC had current year earnings, the Company's share
     of  net  losses  since inception continued to exceed the carrying amount of
     the  investment.  Therefore,  the  investment  had been reduced to zero and
     equity  and  earnings  would  not  have been recognized until the Company's
     share  of  net  income  equaled  its  share  of  unrecognized  net  losses.

     During  June  2004,  the  Company  sold its' membership interest in BEC for
     gross  proceeds  of  $9.2  million.  A  pre-tax  gain  of  $7.4 million was
     recognized and a liability of $1.8 million established as a reserve against
     items  for  which  the  Company  was  required to indemnify the buyer for a
     period  of  180  days after closing pursuant to the agreement. Net proceeds
     from  the  sale  are  subject  to  certain  reinvestment  provisions of the
     Company's  Notes.


                                       44
<PAGE>
Summarized financial information for BEC as of and for the years ended December
31, is as follows (in thousands):

<TABLE>
<CAPTION>
                                                  2003       2002       2001
                                                ---------  ---------  --------
<S>                                             <C>        <C>        <C>

Current assets                                  $  7,181   $  6,679   $ 11,336
Oil and gas properties                            96,846    110,555    100,833
Other assets                                       1,326      1,309      1,966
                                                ---------  ---------  --------
  Total assets                                  $105,353   $118,543   $114,135
                                                =========  =========  ========
Current liabilities                             $ 55,736   $ 14,149   $ 14,505
Long-term debt                                         -     63,900     51,700
Other liabilities                                  6,459      7,953      8,092
Redeemable preferred shares                       37,785     34,925     34,287
Members' equity (deficit)                         14,674      2,262      1,764
Accumulated other comprehensive (loss) income     (9,301)    (4,646)     3,787
                                                ---------  ---------  --------
  Total liabilities and equity                  $105,353   $118,543   $114,135
                                                =========  =========  ========
Net sales                                       $ 42,181   $ 38,002   $ 44,173
Operating income                                  18,892     13,872     16,737
Net income                                      $ 17,112   $  4,782   $ 10,259
</TABLE>


     The Company owned working interest in certain oil and gas properties and an
     interest  in  a  drilling rig with BECLP. The Company completed the sale of
     its' interest in these properties to BECLP for $2.5 million as of September
     2004  with  an  effective  date  of June 30, 2004. As of June 30, 2004, the
     Company  has recognized impairment for these assets of $2.0 million and has
     reclassified  $2.5 million in property assets as assets held for sale which
     is  included  in  other  current  assets.

11.  OPERATING  LEASES

     The  Company has noncancelable operating lease agreements for the rental of
     office  space,  computers  and  other  equipment.  Certain  of these leases
     contain  purchase  options or renewal clauses. Rental expense for operating
     leases  was approximately $1.1 million for the year ended June 30, 2004 and
     $1.4  million  for  each  of  the  years  ended  June  30,  2003  and 2002.

     At  June  30,  2004 future minimum lease payments for each of the next five
     years  and  thereafter  are  as  follows  (in  thousands):

                              2005     $1,131
                              2006        497
                              2007        386
                              2008        370
                              2009        307
                     Thereafter           543
                                       ------
                                       $3,234
                                       ======


                                       45
<PAGE>
12.  RELATED  PARTY  TRANSACTIONS

     The  Company  has entered into a rental arrangement for office space from a
     corporation  in  which  certain  officers  are  shareholders. Rent payments
     totaled  $0.56  million for each of the years ended June 30, 2004, 2003 and
     2002.

     The  Company  sold its' Royalty Trust units to a Foundation controlled by a
     director  of  the  Company, at the then fair market value in December 2003.

     The  Company acquired interests in various Petroleum Exploration Permits in
     New  Zealand  during the year ended June 30, 2003 from an entity controlled
     by  a  former  officer  of  the  Company  for  approximately  $300,000.

     The  Company  advanced funds to certain officers and other related parties,
     at  7%  to  8% interest. Balances totaled $0.2 million at June 30, 2004 and
     $0.3  million  at  June 30, 2003. A provision in the agreements cancels the
     principal  balance  if the employee remains in the continuous employment of
     the  Company  for  three  to  four  years,  depending  on  the  agreement.

     In  1998,  the Company issued promissory notes to certain employees as part
     of a Class A incentive stock purchase agreement, whereby 13,669 shares were
     issued  at  $75 per share. The carrying value of these notes was minimal at
     June  30,  2004  and $0.1 million at June 30, 2003. The notes have interest
     rates  of  6.5% and 8%. A provision in the agreements cancels the principal
     balance  over  a  period  of  four  years  if  the  employee remains in the
     continuous  employment  of  the  Company  through  December  31,  2005.

     Between  1995  and 1997, the Company issued 4,800 shares of common stock as
     part  of  an  incentive  stock  option  agreement  with  two  officers  for
     promissory  notes.  The  carrying  value of these notes was $0.2 million at
     June  30,  2004 and 2003. Interest rates are calculated at LIBOR plus 1.5%.
     No  cancellation  provision was included with this stock incentive program.

     During  fiscal  1999,  the  Company  purchased  from  certain  officers and
     directors,  for  $2.4  million,  volumetric  production  from  wells in New
     Zealand.  Future  production, totaling 3.3 million Mcf, otherwise allocable
     to the officers and directors will be allocated to the Company. The Company
     has recorded the payment as an investment in oil and gas properties. During
     fiscal  years  2003  and  2002, certain officers and directors representing
     approximately  74% of the total production, assigned back their interest in
     these  properties  for  nominal  consideration. The remaining book value of
     this  asset  at  June  30,  2004  is  $1.0  million.


13.  CONTRACT  SETTLEMENTS

     Effective  May  14,  2003,  the Company entered into a Settlement Agreement
     (the  "Agreement")  with  Allegheny  Energy  ("Allegheny")  which  mutually
     resolved  all  outstanding  issues  and  claims.  Under  the Agreement, the
     Company  neither  received  nor paid any cash consideration, but recognized
     the  following  revenue  and expenses as a result of the settlement for the
     year ended June 30, 2003: (i) gas sales of $3.1 million was recognized as a
     result  of  the  termination  and  release  of  the  Gas  Sale  and


                                       46
<PAGE>
     Purchase  Agreement  ("Gas  Contract") dated December 20, 1999 which called
     for  a  prepayment by Allegheny and subsequent delivery of gas volumes from
     the Company to Allegheny and (ii) net other income of $1.4 million was also
     recorded  related  to  the  transaction.


14.  COMMITMENTS  AND  CONTINGENCIES

     In  1993,  the  Company  sold  working interests in certain Appalachian gas
     properties in connection with the formation of the Eastern American Natural
     Gas  Trust  ("Royalty  Trust").  A portion of the proceeds from the sale of
     these  interests,  representing  a term net profits interest, was accounted
     for  as  a  production payment and is currently classified as other current
     and long-term liabilities. As of June 30, 2000, the Company determined that
     due  to  the  rising  cost  of transporting gas, the total deferred revenue
     would not be realizable. Therefore, $4.9 million, the amount related to the
     royalty  portion,  was impaired and $6.2 million, the amount related to the
     term  portion, was reclassified to other current and long-term liabilities.
     These  amounts  are  amortized  as  the  associated  volumes  are sold. The
     remaining  unamortized other current and long-term liabilities are $7.1 and
     $8.1  million  at  June  30,  2004  and  2003,  respectively.

     The  Company  entered  into  a gas sales contract with AFG Industries, Inc.
     ("AFG")  for  the  sale  of  up to 4,000 MMBtu per day from January 1, 2004
     through  December  31,  2004.  AFG  is a "Float Glass" plant adjacent to an
     existing  Company pipeline. The sales contract price is based off the NYMEX
     settlement  price  for  Natural  Gas Henry Hub Futures Contracts each month
     plus  an  Appalachian  Basis  component.

     On November 30, 2001, the Company entered into a natural gas sales contract
     with Mountaineer Gas Company, doing business as Allegheny Power, to deliver
     5,500  Dth per day. Under the pricing terms, the Company will never receive
     less  than  $2.75  per  Dth  plus  the  Columbia  Gas  Transmission ("TCO")
     Appalachia  Basis or more than $4.85 per day plus the TCO Appalachia Basis.
     The  contract  began  on December 1, 2001 and continues through October 31,
     2004.

     The  Company is involved in various legal actions and claims arising in the
     ordinary  course  of  business. Management does not expect these matters to
     have  a  material  adverse  effect  on  the Company's financial position or
     results  of  operations.


15.  FINANCIAL  INSTRUMENTS

     The  estimated  fair  values  of the Company's financial instruments, as of
     June  30,  have  been  determined  using appropriate market information and
     valuation  methodologies.  Considerable judgment is required to develop the
     estimates  of  fair value; thus, the estimates provided are not necessarily
     indicative  of  the  amount that the Company could realize upon the sale or
     refinancing  of  such  financial instruments. The Company in estimating the
     fair  value  of  its  financial  instruments used the following methods and
     assumptions:

     Notes  Receivable  -  The notes receivable accrue interest at a fixed rate.
     -----------------
     The  carrying  value  approximates  fair  value  which  was estimated using
     discounted  cash  flows  based  on  current  interest  rates for notes with
     similar  credit  characteristics  and  maturities.


                                       47
<PAGE>
     Long-Term  Debt  - The Company's subordinated debt is traded publicly.  The
     ---------------
     market  value  at  the end of the year was used for valuation purposes. The
     remaining portion of the Company's long-term debt is comprised of revolving
     lines  of credit with variable rates and fixed rate facilities. At June 30,
     2004,  the fair value of the Company's subordinated debt was $118.5 million
     and  the book value was $126.0 million. At June 30, 2003, the fair value of
     the  Company's  subordinated  debt was $92.4 million and the book value was
     $132.1  million.


     Derivative  Financial  Instruments - All derivative instruments held by the
     ----------------------------------
     Company are designated as hedges, have high correlation with the underlying
     exposure and are highly effective in offsetting underlying price movements.
     Accordingly,  gains  and  losses from changes in derivative fair values are
     deferred  until the underlying transaction occurs. Gains or losses are then
     recognized  in  the  income statement or recorded as part of the underlying
     assets  or  liability, depending on the circumstances. Derivative positions
     are  settled  if the underlying transaction is no longer expected to occur,
     with  the  related  gains  and  losses recognized in earnings in the period
     settlement occurs. Option premiums paid are recorded as assets and expensed
     over  the  life  of the option. Derivatives generally have initial terms of
     less  than  three years, and all currently hedged transactions are expected
     to occur within the next three years. See Note 5 for additional information
     regarding  the  Company's  derivative  holdings.


16.  INDUSTRY  SEGMENTS

     The  Company's  reportable  business segments have been identified based on
     the  differences  in  products  and  service  provided.  Revenues  for  the
     exploration and production segment are derived from the production and sale
     of  natural  gas  and  crude oil. Revenues for the aggregation and pipeline
     segment arise from the aggregation of both Company and third party produced
     natural  gas  volumes  and  the related transportation. Management utilizes
     earnings  before  interest,  income  taxes,  depreciation,  depletion,
     amortization  and  impairment and exploratory costs ("EBITDAX"), a non-GAAP
     financial  measure,  to  evaluate  each  segment's  operations.


                                       48
<PAGE>
     Reconciliation of non-GAAP financial measure is as follows (in thousands):

<TABLE>
<CAPTION>
                                                             Twelve Months Ended June 30
                                                                   (in thousands)
                                                            -----------------------------
                                                              2004      2003      2002
                                                            --------  --------  ---------
<S>                                                         <C>       <C>       <C>

Net income (loss)                                           $ 4,295   $ 9,844   $(26,180)

Add:
  Interest expense                                           15,069    16,383     19,671
  Depletion and depreciation of oil and gas properties       13,300    12,140     12,362
  Depreciation of pipelines, other property and equipment     4,190     4,294      2,934
  Exploration and impairment                                 10,796    11,729     27,693
  Income tax expense (benefit)                               (4,722)    6,073    (16,822)
Subtract:
  Change in accounting principle, net of tax                      -       (73)         -

                                                            --------  --------  ---------
EBITDAX                                                     $42,928   $60,536   $ 19,658
                                                            --------  --------  ---------
</TABLE>


                                       49
<PAGE>
     Summarized financial information for the Company's reportable segments is
     shown in the following table. The "other" column includes items related to
     drilling rig operations and corporate items (in thousands):

<TABLE>
<CAPTION>
                                         Exploration    Aggregation
                                             and            and
                                         Production      Pipeline      Other     Consolidated
                                        -------------  -------------  --------  --------------
<S>                                     <C>            <C>            <C>       <C>
                   2004
Sales to unaffiliated customers         $     62,432   $     60,819   $   122   $     123,373
Depreciation, depletion, amortization         14,721            630     2,139          17,490
Impairment and exploratory costs              10,780             16         -          10,796
Operating profit                              15,381          2,218    (1,477)         16,122
Interest expense, net                         22,180         (7,453)       82          14,809
EBITDAX                                       42,388          2,710    (2,170)         42,928
Total assets                                 174,540         96,362    19,310         290,212
Capital expenditures                          19,012          1,927       971          21,910
----------------------------------------------------------------------------------------------
                   2003
Sales to unaffiliated customers         $     56,907   $     60,484   $    35   $     117,426
Depreciation, depletion, amortization         13,559            661     2,214          16,434
Impairment and exploratory costs              11,729              -         -          11,729
Operating profit                               1,106          3,922     1,257           6,285
Interest expense, net                         21,982         (6,486)      273          15,769
EBITDAX                                       29,125          4,718    26,694          60,537
Total assets                                 191,190         88,831    15,812         295,833
Capital expenditures                          36,147            241     1,244          37,632
----------------------------------------------------------------------------------------------
                   2002
Sales to unaffiliated customers         $     44,429   $     41,209   $   504   $      86,142
Depreciation, depletion, amortization         13,741            859       696          15,296
Impairment and exploratory costs              26,127             89     1,478          27,694
Operating profit (loss)                      (22,507)           330    (2,292)        (24,469)
Interest expense, net                         21,238         (6,922)    3,663          17,979
EBITDAX                                       18,795          1,498      (635)         19,658
Total assets                                 186,587         78,226    39,923         304,736
Capital expenditures                          33,679            145     4,470          38,294
----------------------------------------------------------------------------------------------
</TABLE>

     Operating  profit  represents  revenues  less  costs  which  are  directly
     associated  with  such  operations.  Revenues  are priced and accounted for
     consistently  for  both  unaffiliated  and  intersegment sales. The 'Other'
     column  includes  items  related  to  non-reportable  segments,  including
     drilling  rig, corporate and elimination items. Included in the exploration
     and  production segment are net long-lived assets located in New Zealand of
     $7.4  million, $6.1 million and $3.4 million, as of June 30, 2004, 2003 and
     2002, respectively and revenues of $0.3 million for the year ended June 30,
     2004 with no significant revenue recorded for the years ended June 30, 2003
     and  June  30,  2002.


                                       50
<PAGE>
     Revenues  from  two  purchasers of the Company's production during the year
     ended  June 30, 2004 represent $24.1 million and $12.8 million respectively
     of  the  Company's  consolidated  revenues  within  the  Exploration  and
     Production and Gas Aggregation and Pipeline segments. During the year ended
     June  30,  2003, revenues from three purchasers of the Company's production
     represented  $17.0 million, $16.5 million and $14.6 million respectively of
     the  Company's  consolidated revenues within the Exploration and Production
     and  Gas  Aggregation  and  Pipeline  segments.

17.  SELECTED  QUARTERLY  FINANCIAL  DATA  (UNAUDITED)

     The  following  represents selected quarterly financial information for the
     years  ended  June  30  (in  thousands,  except  per  share  data):

<TABLE>
<CAPTION>
                                                    Quarter Ended
                                 ---------------------------------------------------
           2004                   September 30    December 31   March 31    June 30
                                 --------------  -------------  ---------  ---------
<S>                              <C>             <C>            <C>        <C>
Total revenue                    $      31,041   $     30,272   $  32,204  $ 29,856
Gross profit (loss)                      3,911          2,893       4,510     4,808
Income per share (a)
          basic                           0.91          (0.53)       6.98     (0.91)
          diluted                         0.89          (0.53)       6.88     (0.91)
 Net income (loss)                         587           (348)      4,631      (575)
                                                    Quarter Ended
                                 ---------------------------------------------------
           2003                  September 30    December 31    March 31   June 30
                                 --------------  -------------  ---------  ---------
Total revenue                    $      22,589   $     26,383   $  34,038  $ 34,416
Gross profit (loss)                        448         (1,735)      3,506     4,066
Income (loss) before change in
accounting principle                    (1,562)         8,320       3,347      (188)
Income per share
          basic                          (2.43)         12.77        5.15     (0.38)
          diluted                        (2.43)         12.49        5.04     (0.38)
 Net income (loss)                      (1,562)         8,320       3,347      (261)
</TABLE>


     18.  SUBSEQUENT  EVENT

     As  previously  reported,  the  Company had been in litigation with certain
     Holders  of its $200,000,000 9 1/2% Senior Subordinated Notes due 2007 (the
     "Noteholders")  (the  "Notes"). The dispute involved the calculation of the
     Net  Proceeds  of  an  Asset Sale as defined in the Indenture dated May 23,
     1997  between  the  Company  and  The Bank of New York. The Company and the
     Noteholders  have  settled  the  dispute, as memorialized in the Settlement
     Agreement  executed  as  of February 24, 2004, and attached to the Form 8-K
     filed by the Company on February 24, 2004 as Exhibit 99.11 (the "Settlement
     Agreement").  In settlement of the dispute the Company agreed to repurchase
     $38  million in Notes. The Company met its obligations under the Settlement
     Agreement having finalized the first Asset Sale Offer (as defined under the
     Indenture)  in  the  amount  of $4 million on March 24, 2004 and the second
     Asset  Sale  Offer in the amount of $34 million, at face value, on July 29,


                                       51
<PAGE>
     2004.  The  United  States District Court for the Southern District of West
     Virginia  has  entered  a  Dismissal  Order  dismissing the litigation with
     prejudice.

     At  June 30, 2004, the Company classified $34 million of the Notes that was
     paid  on  July  29, 2004 as long term debt as a result of having an amended
     and  restated  credit  agreement  in  place  that  allowed  the  Company to
     refinance  the  debt  on  a  long  term  basis.


SUPPLEMENTAL  INFORMATION  ON  OIL  AND  GAS  PRODUCING  ACTIVITIES  (UNAUDITED)

Costs  -  The  following  tables set forth capitalized costs and costs incurred,
-----
including  capitalized  overhead,  for  oil and gas producing activities for the
years  ended  June  30  (in  thousands):

<TABLE>
<CAPTION>
                                                       2004        2003       2002
                                                    ----------  ----------  ---------
<S>                                                 <C>         <C>         <C>
Capitalized costs:
  Proved properties                                 $ 337,451   $ 327,958   $310,495
  Unproved properties                                   8,105       9,946      9,653
                                                    ----------  ----------  ---------
  Total                                               345,556     337,904    320,148
  Less accumulated depletion and depreciation        (119,613)   (107,233)   (97,523)
                                                    ----------  ----------  ---------
Net capitalized costs                               $ 225,943   $ 230,671   $222,625
                                                    ==========  ==========  =========

Company's share of equity method investee's net
  capitalized costs (see Note 10)                   $       -   $  27,167   $ 23,908
                                                    ==========  ==========  =========

Costs incurred:
  Acquisition of proved and unproved properties     $      72   $   5,879   $    717
  Development costs                                     7,892      14,105     10,977
  Exploration costs                                    10,449      15,292     20,737
                                                    ----------  ----------  ---------
Total costs incurred                                $  18,413   $  35,276   $ 32,431
                                                    ==========  ==========  =========

Company's share of equity method investee's total
  costs incurred (see Note 10)                      $   3,329   $   7,674   $  2,309
                                                    ==========  ==========  =========
</TABLE>


                                       52
<PAGE>
Results  of  Operations  -  The  results of operations for oil and gas producing
-----------------------
activities,  excluding corporate overhead and interest costs for the years ended
June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                     2004     2003      2002
                                                    -------  -------  --------
<S>                                                 <C>      <C>      <C>
Revenues from sale of oil and gas                   $57,203  $51,410  $38,939
Less:
  Production costs                                    6,454    4,436    5,001
  Production taxes                                    4,143    3,233    2,077
  Exploration and impairment                          9,578   11,729   27,605
  Depletion, depreciation and amortization           13,300   12,140   12,362
  Income tax expense (benefit)                        9,432    7,353   (2,999)
                                                    -------  -------  --------
Income (loss) from oil and gas operations           $14,296  $12,519  $(5,107)
                                                    =======  =======  ========

Company's share of equity method investee's
  income from oil and gas operations (see Note 10)  $ 5,846  $ 4,354  $ 4,955
                                                    =======  =======  ========
</TABLE>


Production costs include those costs incurred to operate and maintain productive
wells  and  related  equipment  and  include  costs  such  as labor, repairs and
maintenance, materials, supplies, fuel consumed and insurance.  Production costs
are  net of well tending fees, which are included in well operations revenues in
the  accompanying  consolidated  statements  of  operations.

Exploration  and  impairment  expenses  include  the  costs  of  geological  and
geophysical  activity,  unsuccessful  exploratory wells and leasehold impairment
allowances.

Depletion,  depreciation  and  amortization  include  costs  associated  with
capitalized  acquisitions,  exploration  and  development  costs.

The  provision  for income taxes is computed at the statutory federal income tax
rate  and  is  reduced  to  the  extent of permanent differences which have been
recognized  in  the Company's tax provision, such as investment tax credits, and
the  utilization  of  Federal  tax  credits  permitted  for fuel produced from a
non-conventional  source.


Reserve  Quantity  Information  -  Reserve  estimates  are  subject  to numerous
------------------------------
uncertainties inherent in the estimation of quantities of proved reserves and in
the  projection  of  future  rates  of  production  and  timing  of  development
expenditures.  The  accuracy  of  such estimates is a function of the quality of
available  data  and  of engineering and geological interpretation and judgment.
Results  of  subsequent drilling, testing and production may cause either upward
or  downward  revisions  of previous estimates.  Further, the volumes considered
commercially  recoverable  fluctuate with changes in prices and operating costs.
Reserve  estimates,  by  their  nature,  are  generally  less precise than other
financial  statement  disclosures.


                                       53
<PAGE>
The  following table sets forth information for the years indicated with respect
to  changes  in the Company's proved reserves, substantially all of which are in
the  United  States.

<TABLE>
<CAPTION>
                                                                 Natural Gas   Crude Oil
                                                                    (Mmcf)      (Mbbls)
                                                                 ------------  ----------
<S>                                                              <C>           <C>
Proved reserves:
  June 30, 2001                                                      206,456       2,633
    Revisions of previous estimates                                  (23,812)         74
    Extensions and discoveries                                        10,642         368
    Purchases of reserves in place                                         -           -
    Production                                                        (9,941)       (124)
                                                                 ------------  ----------
  June 30, 2002                                                      183,345       2,951
    Revisions of previous estimates                                  (11,847)       (964)
    Extensions and discoveries                                        23,623         580
    Sales of reserves in place                                        (2,941)        (16)
    Purchases of reserves in place                                     8,371           -
    Production                                                        (9,755)       (185)
                                                                 ------------  ----------
  June 30, 2003                                                      190,796       2,366
                                                                 ============  ==========
    Revisions of previous estimates                                    9,309        (252)
    Extensions and discoveries                                        28,732         176
    Sales of reserves in place                                        (2,644)       (903)
    Purchases of reserves in place                                         -           -
    Production                                                       (10,718)       (107)
                                                                 ------------  ----------
  June 30, 2004                                                      215,475       1,280
                                                                 ============  ==========

Proved developed reserves:
  June 30, 2002                                                      160,224       1,135
  June 30, 2003                                                      161,796       1,064
  June 30, 2004                                                      170,131         626

Company's share of equity method investee's proved reserve at:
  June 30, 2002                                                        7,445      12,063
  June 30, 2003                                                        7,755      11,427
  June 30, 2004 (See Note 10)                                              -           -
</TABLE>


Standardized  Measure of Discounted Future Net Cash Flows - Estimated discounted
---------------------------------------------------------
future  net  cash  flows  and changes therein were determined in accordance with
SFAS  No.  69,  "Disclosures  About  Oil and Gas Producing Activities."  Certain
information concerning the assumptions used in computing the valuation of proved
reserves  and  their  inherent  limitations  are  discussed  below.  The Company
believes such information is essential for a proper understanding and assessment
of  the data presented.  Future cash inflows are computed by applying period-end
prices  of  oil  and  gas  relating  to  the  Company's  proved  reserves to the
period-end  quantities  of  those reserves.  Future price changes are considered
only  to  the  extent  provided  by  contractual  arrangements  in  existence at
period-end.


                                       54
<PAGE>
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, or their present
worth.  In  addition,  variations  from the expected production rates also could
result  directly  or  indirectly  from factors outside of the Company's control,
such  as  unintentional  delays  in development, changes in prices or regulatory
controls.  The  reserve  valuation  further  assumes  that  all reserves will be
disposed  of  by production.  However, if reserves are sold in place, this could
affect  the  amount  of  cash  eventually  realized.

Future  development  and  production  costs  are  computed  by  estimating  the
expenditures  to  be incurred in developing and producing the proved oil and gas
reserves  at  the  end  of  the  year,  based  on  period-end costs and assuming
continuation  of  existing  economic  conditions.

Future  income  tax  expenses  are computed by applying the appropriate year-end
statutory  tax  rates and existing tax credits, with consideration of future tax
rates  already  legislated,  to the future pretax net cash flows relating to the
Company's  proved  oil  and  gas  reserves.

An  annual discount rate of 10% was used to reflect the timing of the future net
cash  flows  relating  to  proved  oil  and  gas  reserves.

Information  with  respect to the Company's estimated discounted future net cash
flows related to its proved oil and gas reserves as of June 30 is as follows (in
thousands):

<TABLE>
<CAPTION>
                                                        2004         2003         2002
                                                     -----------  -----------  ----------
<S>                                                  <C>          <C>          <C>
Future cash in flows                                 $1,429,645   $1,152,845   $ 715,755
Future production and development costs                (355,438)    (235,960)   (243,828)
Future income tax expense                              (308,000)    (290,000)   (116,000)
                                                     -----------  -----------  ----------
Future net cash flows before discount                   766,207      626,885     355,927
10% discount to present value                          (455,663)    (365,662)   (205,014)
                                                     -----------  -----------  ----------
Standardized measure of discounted future net cash
  flows related to proved oil and gas reserves       $  310,544   $  261,223   $ 150,913
                                                     ===========  ===========  ==========

Company's share of equity method investee's
  standardized measure of discounted future net
  cash flows (See Note 10)                           $        -   $   67,375   $  53,838
                                                     ===========  ===========  ==========
</TABLE>


                                       55
<PAGE>
Principal changes in the standardized measure of discounted future net cash flow
for  the  years  ended  June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                    2004       2003       2002
                                                  ---------  ---------  ---------
<S>                                               <C>        <C>        <C>
Standardized measure of discounted future
  net cash flows at beginning of period           $261,223   $150,913   $172,281
Sales of oil and gas produced, net of
  production costs                                 (41,724)   (35,155)   (26,525)
Net changes in prices and production costs          21,120    175,844    (13,507)
Changes in production rates and other              (16,394)    (5,484)    (5,867)
Extensions, discoveries and other additions, net
  of future production and development costs        60,609     52,407     13,622
Changes in estimated future development costs      (18,826)   (16,243)    (4,820)
Development costs incurred                           7,892     14,105     10,977
Revisions of previous quantity estimates            15,866    (34,089)   (24,772)
Purchase of reserves in place                            -     16,185          -
Accretion of discount                               28,073     15,246     17,228
Net change in income taxes                          (7,295)   (72,506)    12,296
                                                  ---------  ---------  ---------
Standardized measure of discounted
  future net cash flows at end of period          $310,544   $261,223   $150,913
                                                  =========  =========  =========
</TABLE>

                                    * * * * *


                                       56
<PAGE>
              ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
              -----------------------------------------------------
                     ON ACCOUNTING AND FINANCIAL DISCLOSURE
                     --------------------------------------

     There  have  been  no  changes  in  or  disagreements  with  accountants on
accounting  and  financial  disclosure.

                        ITEM 9A.  CONTROLS AND PROCEDURES
                        ---------------------------------

     Under  the  supervision  and  with  the  participation  of  our management,
including  our  principal executive officer and principal financial officer, the
Company  has  evaluated  the  effectiveness  of  the design and operation of our
disclosure  controls  and  procedures  within 90 days of the filing date of this
annual  report  and,  based on their evaluation, our principal executive officer
and  principal  financial  officer  have  concluded  that  these  controls  and
procedures  are  effective.  There  were  no significant changes in our internal
controls  or  in  other  factors  that could significantly affect these controls
subsequent  to the date of their evaluation.  Disclosure controls and procedures
are  our  controls  and  other  procedures  that  are  designed  to  ensure that
information required to be disclosed by us in the reports that we file or submit
under  the  Securities Exchange Act of 1934, as amended, is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange  Commission's  rules  and  forms.  Disclosure  controls  and procedures
include,  without  limitation,  controls  and procedures designed to ensure that
information required to be disclosed by us in the reports that we file under the
Securities  Exchange  Act  is  accumulated  and  communicated to our management,
including  our  principal  executive officer and principal financial officer, as
appropriate  to  allow  timely  decisions  regarding  required  disclosure.

                                    PART III
                                    --------

                  ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT
                  ---------------------------------------------

          The  executive officers and Directors of the Company and the executive
officers  of its subsidiaries on June 30, 2004 are listed below, together with a
description  of  their  experience  and  certain  other information.  All of the
Directors  were  elected  or  re-elected  for  a  one year term at the Company's
December  2003 annual meeting of stockholders.  Executive officers are appointed
by  the  Board  of  Directors.

<TABLE>
<CAPTION>
         Name                          Position with Company or Subsidiary
-----------------------       -----------------------------------------------------
<S>                      <C>  <C>

John Mork                 56  President and Chief Executive Officer; Director
Joseph E. Casabona        60  Executive Vice President; Director
Michael S. Fletcher       55  Chief Financial Officer
Donald C. Supcoe          48  Senior Vice President, Secretary and General Counsel
J. Michael Forbes         44  Vice President and Treasurer
George V. O'Malley        52  Vice President Accounting
K. Ralph Ranson, II       61  Vice President Marketing
C. Clark Clement, Jr.     55  Vice President Western Operations
Julie Ann Kitano          47  Assistant Secretary
W. Gaston Caperton, III   63  Director
Peter H. Coors            56  Director
L. B. Curtis              79  Director (Chairman)
John J. Dorgan            79  Director
F. H. McCullough, III     56  Director
Julie Mork                53  Director
Arthur C. Nielsen, Jr.    84  Director
Jay S. Pifer              67  Director
</TABLE>


                                       57
<PAGE>
     W.  Gaston Caperton, III has been a Director of the Company since 1997.  He
served as the Governor of the State of West Virginia for two terms, from 1989 to
1997.  Governor Caperton is President and Chief Executive Officer of The College
Board  and  President of the Caperton Group.  Governor Caperton presently serves
on  the  Board  of  Directors of Owens Corning, United Bankshares, West Virginia
Media  Holdings,  the  Benedum  Foundation,  National  Center  for  Learning
Disabilities,  Classroom,  Inc.  and  Prudential  Financial.

     Joseph E. Casabona  is Executive Vice President of the Company and has been
a  Director  since  its formation.  Mr. Casabona joined Eastern American in 1985
and  was  Executive  Vice President of Eastern American and a Director from 1987
until  1993.  Mr.  Casabona  was  employed  from 1967 to 1979 in the Pittsburgh,
Pennsylvania  office  of  KPMG  Main  Hurdman  ("KPMG, Peat Marwick"), Certified
Public  Accountants, became a partner in the Firm in 1980 and was named Director
of  Accounting  and  Auditing  of  the  Pittsburgh office in 1983.  Mr. Casabona
graduated from the University of Pittsburgh with a Bachelor of Science Degree in
Business  Administration  and from the Colorado School of Mines with a Master of
Science  Degree in Mineral Economics.  He has been a Certified Public Accountant
since  1969.  Mr.  Casabona  serves on the Board of Directors of Gonex, Inc. and
has  been  a  member  of  the  Board  of  Directors  of  the  West  Virginia and
Pennsylvania  Independent  Oil  and  Gas  Associations.

     Clark  Clement has been Vice-President of Western Operations since 2003 and
is  responsible for the Company's operations in the west, including New Zealand.
Mr.  Clement  has  thirty-four years of experience in the oil industry including
positions  with  major service companies, independents, and a major oil company.
Prior to joining the Company in 2001, he held positions with BP as Drilling Team
Leader  in  the  Mid-Continent  Asset  of  the  U.S.  and  Well  Engineering and
Operations  Superintendent  in  Colombia,  South  America.  Mr.  Clement holds a
Bachelor of Science Degree in Chemistry from New Mexico Highlands University and
is  a Registered Professional Engineer in Petroleum Engineering.  He has written
over  fifty  technical papers, holds five U.S. patents, several foreign patents,
and  is  a  member  of  the  Society  of Petroleum Engineers, American Petroleum
Institute,  American  Association  for  Drilling  Engineers and Oilfield Helping
Hands.

     Peter H. Coors has been a Director of the Company since 1996.  Mr. Coors is
Chairman  of  Coors  Brewing  Company  and Chairman of Adolph Coors Company.  He
received  his  Bachelor Degree in Industrial Engineering from Cornell University
in  1969  and  he  earned  his Master Degree in Business Administration from the
University  of  Denver in 1970.  Mr. Coors also serves on the Board of Directors
of  U.  S.  Bancorp,  Inc.  and  H.J. Heinz Company.  Mr. Coors is a trustee and
member  of  the  executive board of the Denver Area Council of the Boy Scouts of
America  and  a member of the executive committee for the National Western Stock
Show  Association.  He  is  also  a member of the International Chapter of Young
Presidents'  Organization,  a  member  of  the  Board  of University of Colorado
Hospital,  and a trustee for the Adolph Coors Foundation, Castle Rock Foundation
and  Seeds  of  Hope  Foundation.

     L.B.  Curtis  has  been  a  Director of the Company since 1993 and Chairman
since 1998.  Mr. Curtis was a Director of Eastern American from 1988 until 1993.
Mr.  Curtis  is retired from a career at Conoco, Inc. where he held the position
of  Vice  President of Production Engineering with Conoco Worldwide.  Mr. Curtis
was highly recognized across the Petroleum Industry in the upstream (exploration
and production) segment of the industry.  Mr. Curtis graduated from The Colorado
School  of  Mines  with  an  Engineer  of  Petroleum  Professional  Degree.

     John J. Dorgan has been a Director of the Company since 1993.  He served as
a  Director  for  Eastern  American  in  1992.  He  is  a  former Executive Vice
President and consultant to Occidental Petroleum Corporation where he had worked
in  various  capacities  starting  in  1972.


                                       58
<PAGE>
     Michael  S.  Fletcher has been Chief Financial Officer of the Company since
December,  1999.  He  also  held  the  position of Treasurer of the Company from
December,  1999 through December, 2000.  In addition, Mr. Fletcher was President
of  Mountaineer  Gas  Company  from  1998  until the Company sold Mountaineer in
August  of  2000.  Prior to becoming President in 1998, he held the positions of
Senior  Vice  President  and  Chief  Financial  Officer  of Mountaineer.  Before
joining  Mountaineer  in 1987, Mr. Fletcher was a partner of Arthur Andersen and
Company  and  was  employed  by  that firm for fifteen years.  Mr. Fletcher is a
Certified  Public  Accountant  and  a graduate from Utah State University with a
Bachelor  Degree  in  Accounting.

     J.  Michael  Forbes  is  Vice  President and Treasurer of the Company.  Mr.
Forbes  has  been  an officer of the Company since 1995 and prior to that was an
officer  with  Eastern  American, which he joined in 1982.  Mr. Forbes graduated
with  a  Bachelor of Arts in Accounting and Finance from Glenville State College
and  is  a  Certified  Public  Accountant.  He  also  holds a Master of Business
Administration  from  Marshall  University  and  is  a  graduate  of  Stanford
University's  Program  for  Chief  Financial  Officers.

     Julie  Ann  Kitano  has  been  Assistant  Secretary  of  the  Company since
December,  2000.  Ms.  Kitano  joined  the  Company in 1998 as a Paralegal.  She
holds  a  Bachelor  of  Arts  Degree  from  Whitman  College.

     F.  H.  McCullough, III has been a Director of the Company since 1993.  Mr.
McCullough  was  a  Director  of  Eastern  American  from  1978 until 1993.  Mr.
McCullough  joined  Eastern  American  in  1977 and served in various capacities
until  1999.  Mr.  McCullough  is  a  graduate  of  the  University  of Southern
California  with  a  Bachelor  of Arts Degree in International Economics and two
Masters Degrees in Business Administration and Financial Systems Management.  He
is  a  graduate  of  the  Northwestern  University  Kellogg  Graduate  School of
Management  Executive  Marketing  Program.

     John Mork has been President and Chief Executive Officer of the Company and
a  Director  of  the  Company  since  its formation.  Mr. Mork served in various
capacities at Union Oil Company until 1972 when he joined Pacific States Gas and
Oil, Inc. and subsequently founded Eastern American.  Mr. Mork was President and
a  Director  of  Eastern  American  from  1973  until  1993.  Mr. Mork is a past
Director  of  the  Independent  Petroleum  Association  of  America,  and  the
Independent  Oil and Gas Association of West Virginia.  Mr. Mork was a member of
and  held  various  positions  with  the  Young  Presidents'  Organization  from
1984-1998.  He  also founded the Mountain State Chapter of the Young Presidents'
Organization  located in Charleston, West Virginia.  He is currently a member of
the  Chief  Executives  Organization,  the  World  President's Organization, the
University  of  Southern California Engineering School Board of Councilors and a
Trustee  of  the Denver Museum of Nature and Science.  Mr. Mork holds a Bachelor
of  Science  Degree  in  Petroleum  Engineering  from the University of Southern
California  and  he  is  a  graduate of the Stanford Business School Program for
Chief  Executive  Officers.  He  is  the  husband  of  Julie  Mork.

     Julie  M.  Mork  has  been a Director of the Company since 1993.  She was a
Director  of  Eastern  American  from  1974  until  1993.  Mrs. Mork served as a
founder  and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern
American.  She  is currently Managing Director of the ECA Foundation, Inc.  Mrs.
Mork  received  a  Bachelor  of  Arts  Degree  in History from the University of
California  in  Los  Angeles.  She  is  the  wife  of  John  Mork.

     George  V.  O'Malley  has been Vice President of Accounting for the Company
since December 2002. Before being elected Vice President, Mr. O'Malley served as
Director  of  Accounting. Mr. O'Malley joined Eastern American in April 1991 and
served  in  various  capacities including Vice President and Treasurer. Prior to
joining  the  Company,  he  held  various  positions  in  industry  and  public
accounting.  Mr.  O'Malley  currently  serves  as President of the West Virginia
Society  of  CPA's  and  as a member of the Board of the Independent Oil and Gas


                                       59
<PAGE>
Association  of  West  Virginia. Mr. O'Malley graduated from Marshall University
with  a  Bachelor's  Degree  in Accounting and is a Certified Public Accountant.

     Arthur  C.  Nielsen, Jr. Chairman Emeritus of A.C. Nielsen Co.,  has been a
Director  of the Company since 1993.  He was a Director of Eastern American from
1985  until  1993.  He  serves  on  the  Board  of  Directors of General Binding
Corporation.

     Jay  S.  Pifer  has  been  a Director of the Company since 2003.  Mr. Pifer
recently  retired as Chief Operating Officer of Allegheny Energy with over forty
years of service, where he was responsible for managing over 12,000 megawatts of
generating  facilities  and  providing  electric  and  gas  service to over four
million people in Pennsylvania, West Virginia, Maryland, Virginia and Ohio.  Mr.
Pifer  graduated  from  Clarion  University  and  Penn State University where he
received  the  Outstanding Engineering Alumni Award and the Alumni Fellow Award.
Mr.  Pifer  serves  on  the  boards  of  numerous  community  organizations.

     K.  Ralph  Ranson, II has been Vice President of Marketing and Land for the
Company since December, 2000.  He joined Eastern American in 1993 and has served
in  various  capacities,  most  recently  as  Vice  President of Land.  Prior to
joining  Eastern  American,  Mr.  Ranson  worked  as  an independent oil and gas
consultant,  was  an  officer  with  Alamco, Inc. and an officer and director of
Union  Drilling, Inc.  Mr. Ranson is past President of the Independent Oil & Gas
Association of West Virginia, where he served two consecutive terms.  Mr. Ranson
received  a  Bachelor  of  Arts  Degree  from  West  Virginia  Wesleyan College.

     Donald  C.  Supcoe  is  the  Senior Vice President, Corporate Secretary and
General  Counsel  of the Company and is responsible for the Company's operations
in  the  east,  which includes Eastern American.  Mr. Supcoe was the Senior Vice
President of Mountaineer Gas Company from 1998 until its sale in August of 2000.
Prior to joining Mountaineer in 1998, he was the Vice President, General Counsel
and  Corporate  Secretary  of Eastern American with whom he had been employed in
various positions since 1981.  Mr. Supcoe is a past President of the Independent
Oil  and  Gas  Association  of  West  Virginia  and a past Vice President of the
Independent  Petroleum  Association  of America.  Mr. Supcoe graduated from West
Virginia  University  with  a  Bachelor  of  Science  Degree  in  Business
Administration.  Mr.  Supcoe received a Doctor of Jurisprudence Degree from West
Virginia  University  College  of  Law.


                                       60
<PAGE>
                        ITEM 11. EXECUTIVE COMPENSATION
                        -------------------------------

     The  following  table  sets  forth  for fiscal year 2004 the total value of
compensation  of  (i)  the Company's Chief Executive Officer and (ii) each other
executive  officer  of  the  Company.

<TABLE>
<CAPTION>
                                            Annual Compensation
                                          ------------------------                   All Other
                                          Year   Salary    Bonus          Other   Compensation (1)
                                          ----  --------  --------       -------  ----------------
<S>                                       <C>   <C>       <C>       <C>  <C>      <C>
John Mork                                 2004  $315,166  $372,880  (2)  $49,864       $8,873
   President and Chief Executive Officer  2003   265,376   125,000        77,045        5,867
                                          2002   258,892   125,000        59,670       26,067

Joseph E. Casabona                        2004  $250,919  $259,755  (3)  $19,128       $5,803
   Executive Vice President               2003   243,595    80,000         6,875        4,763
                                          2002   238,277   125,942         2,905        4,574

Michael S. Fletcher                       2004  $244,536  $842,040  (4)  $20,275       $6,077
   Chief Financial Officer                2003   238,504    45,000         2,477        4,558
                                          2002   233,306   100,510           352        4,504

Edward J. Davies                          2004  $245,434  $135,000  (5)  $     -       $6,514
   Senior Vice President                  2003   230,201    45,000           408        6,113
                                          2002   223,930    95,714           120        4,592

Donald C. Supcoe                          2004  $208,919  $569,530  (6)  $13,111       $4,433
   Senior Vice President                  2003   201,152    65,000         3,529        4,005
                                          2002   197,993   100,435         2,325        3,949
<FN>
_______________________________
(1)  Includes  compensation  related  to  insurance  policies  provided  for the
     benefit  of  named  officer  and  401K  matching  contributions.
(2)  Includes  stock  based  award  of  $22,880.
(3)  Includes stock based award of $22,880 and Class A stock note forgiveness of
     $46,875.
(4)  Includes  Class  A  stock  note forgiveness of $46,875, employment contract
     stock  of  $338,910  and  employment contract note forgiveness of $286,255.
(5)  Mr.  Davies  left  the  Company  as  of  June  22,  2004.
(6)  Includes  Class  A  stock  note forgiveness of $28,131, employment contract
     stock  of  $201,344  and  employment contract note forgiveness of $170,055.
</TABLE>

     DIRECTOR  COMPENSATION.  Directors  are compensated $2,000 per meeting plus
     ----------------------
reimbursement  for  travel  and  related  expenses.  The  Chairman  of the Board
receives an additional $50,000.    Each Director also receives 160 shares of the
Company's  Class A Stock.  The total Board of Directors' compensation for fiscal
2004  was  $0.1  million.


                                       61
<PAGE>
    ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
    ------------------------------------------------------------------------

     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the  share  ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company  by  all directors and executive officers as a group, in each case as of
September  23,  2004.


                                       62
<PAGE>
     The  business  address  of  each  officer and director listed below is: c/o
Energy  Corporation  of  America,  4643  S. Ulster, Suite 1100, Denver, Colorado
80237.


                                                     Beneficial  Ownership
                                                        Common Stock
                                                    ----------------------
                                                      Shares     Percent
                                                    ----------  ----------
W. Gaston Caperton, III                                  6,930       1.15%
Joseph E. Casabona                                      31,376       5.21%
Colstab & Co. (Nominee for KWB Trust) (1)               35,443       5.88%
Peter H. Coors                                           3,196          *
L. B. Curtis                                            11,210       1.86%
John J. Dorgan                                           4,130          *
J. Michael Forbes                                        2,200          *
F. H. McCullough, III (2)                               70,035      11.63%
John Mork (3)                                          359,493      59.67%
Julie Mork (3)                                         359,493      59.67%
Arthur C. Nielsen, Jr.                                  36,480       6.06%
Donald C. Supcoe                                         3,583          *
                                                    ----------  ----------
                                                       564,076      93.63%

All officers and directors as a group (11 persons)     528,633      87.75%
_______________
*  Less than one percent.

     (1)  Pursuant  to  an  Agreement  dated  December  28, 1998, the Company is
          required  to purchase all shares owned by Kenneth W. Brill upon notice
          by  Mr. Brill's estate or promptly after the passage of two years from
          Mr. Brill's death if the estate does not sooner tender the shares. The
          Company  entered  into a repurchase agreement on January 21, 2004 with
          the  KWB  Trust  to  define  the  purchase  price  and  establish  the
          conditions  for the repurchase of stock owned by the Kenneth W. Brill,
          estate.  The  agreement  outlines  the  repurchase of 49,110 shares of
          stock by the Company or through third parties, at an anticipated value
          of  approximately  $3.7 million over the next five years, and provides
          for  payments  in twenty quarterly installments on the majority of the
          shares  to  be  repurchased.  The  repurchase  of shares is subject to
          certain  restrictions  in the Company's credit agreements. On June 30,
          2004,  the  Company's  remaining  repurchase  obligation  under  the
          Agreement  is  approximately  $2.9  million. Upon adoption of SFAS No.
          150,  as  described  in  Note  2,  $1.4  million of the obligation was
          reclassified as a liability and the remaining $1.5 million is included
          in  stockholders' equity as third parties have agreed to purchase such
          amount.
     (2)  Includes  67,955  shares  held  by  F.H.  McCullough,  III  and  Kathy
          McCullough  as  joint  tenants,  880  shares  held by the Katherine F.
          McCullough Trust, and 400 shares held by each of the Lesley McCullough
          Trust, the Meredith McCullough Trust and the Kristin McCullough Trust.
     (3)  Includes  280,930 shares held by John and Julie Mork as joint tenants,
          2,663  shares  held by Julie Mork individually, and 37,950 shares held
          by  each  of  the  Alison  Mork  Trust  and  the  Kyle  Mork  Trust.


                                       63
<PAGE>
     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial  owner  of  more  than 5% of the outstanding shares of Class A Stock,
(ii)  the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive  officers  as  a  group,  in  each case as of September 23, 2004.  The
business  address  of  each  officer  and  director listed below is:  c/o Energy
Corporation  of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado
80237.

                                                     Beneficial Ownership
                                                         Class A Stock
                                                    ----------------------
                                                      Shares     Percent
                                                    ----------  ----------
W. Gaston Caperton, III                                  2,080       4.50%
Joseph E. Casabona (2)                                   3,529       7.64%
C. Clark Clement, Jr. (2)                                  450          *
Peter H. Coors                                           2,750       5.95%
L.B. Curtis                                              1,720       3.72%
John J. Dorgan                                           2,480       5.37%
Michael S. Fletcher (2)                                  4,105       8.89%
J. Michael Forbes (2)                                      750       1.62%
F.H. McCullough, III                                     1,246       2.70%
John Mork (1)                                            5,377      11.64%
Julie Mork (1)                                           5,377      11.64%
Arthur C. Nielsen, Jr.                                   3,240       7.01%
George V. O'Malley (2)                                     420          *
K. Ralph Ranson, II (2)                                    987       2.14%
Donald C. Supcoe (2)                                     3,685       7.98%
                                                    ----------  ----------
                                                        32,819      71.04%

All officers and directors as a group (15 persons)      32,819      71.04%
_______________
   *  Less than one percent.

(1)  Includes  1,116  shares  held  by  John and Julie Mork as joint tenants and
     1,822  shares  held by Julie Mork individually and 1,220 shares held by the
     Alison  Mork  Trust  and  1,219  shares  held  by  the  Kyle  Mork  Trust.
(2)  Includes  shares  of  Restricted  Class  A  stock.


                                       64
<PAGE>
            ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
            --------------------------------------------------------

     Certain officers and Directors of the Company and members of their families
("participants") regularly participate in the wells drilled by the Company on an
actual  costs basis and share in the costs and revenues on the same basis as the
Company.  The  Company  has  the  right  to  select  the  wells drilled and each
participant  is involved in all wells included within a Company drilling program
(the  "Drilling  Program")  and  cannot selectively choose the wells in which to
participate.  The  following  table  identifies  the  participants'  aggregate
investment  in  the  calendar  years  shown  (in  thousands):

                            2004       2003       2002
                         ----------  ---------  ---------
                            (3)
Gaston Caperton, III     $  100.01   $   58.05  $   77.58
Joseph E. Casabona          225.06       29.02      38.77
C. Clark Clement             30.00       23.22          -
Peter Coors                  30.00       78.36      77.58
L.B. Curtis                 100.01       78.36      83.36
John J. Dorgan               30.00       17.40      19.39
Michael S. Fletcher          49.50       29.03      38.77
J. Michael Forbes            25.00       14.51      19.39
F.H. McCullough, III         50.00       29.03          -
John Mork (1)               825.00      783.65     833.60
Alison Mork Trust (2)        49.50       29.03      38.77
Kyle Mork Trust (2)          49.50       29.03      38.77
Arthur C. Nielsen, Jr.       50.00       29.03      38.77
George O'Malley              33.00       15.67          -
K. Ralph Ranson, II          25.00       14.51          -
Donald C. Supcoe             25.00       14.51      19.39
                         ----------  ---------  ---------
                         $1,696.58   $1,272.41  $1,324.14
                         ==========  =========  =========

(1)  Interest  of  John  Mork  and  Julie  Mork  held  as  joint  tenants.
(2)  Trusts  for  the  children  of  John  Mork  and  Julie  Mork.
(3)  These  amounts  represent  only  the amounts committed to the 2004 Drilling
     Program,  the  actual  amount of investment may vary based on the number of
     wells  drilled  and  the  related  costs.


                                       65
<PAGE>
     Certain  officers,  Directors  and  key employees of the Company have notes
payable  to  the  Company  related to employee incentive stock options that were
granted  and  exercised.  The  notes  bear  various interest rates, ranging from
LIBOR  to  8%  per  annum.  The  Company is amortizing certain of the notes over
their seven year life and assuming continued employment.  Certain of these notes
will be forgiven one-quarter per year, starting January 1, 2003 .  The following
were  indebted  to  the  Company  (in  thousands):

                      Outstanding     Unamortized
                     Balance as of       as of
                     June 30, 2004   June 30, 2004
                     --------------  --------------
Joseph E. Casabona   $           94  $           14
Michael S. Fletcher              94              14
J. Michael Forbes                96              96
K. Ralph Ranson, II              28               4
Donald C. Supcoe                152             104
                     --------------  --------------
  Total              $          464  $          232
                     ==============  ==============


     During  fiscal  1999,  the  Company  purchased  from  certain  officers and
directors  volumetric  production from wells in New Zealand.  Future production,
otherwise  allocable  to  the  officers  and  directors will be allocated to the
Company.  The  following  table identifies the participants' interest as of June
30,  2004:

                          Payment      Volumes
                      (in thousands)    Mmcf
                      ---------------  -------
Joseph E. Casabona    $            50     66.7
L.B. Curtis                        75    100.0
John J. Dorgan                     50     66.7
F.H. McCullough, III              150    200.0
                      ---------------  -------
                      $           325    433.4
                      ===============  =======

     The  Company  rents  office  space in Charleston, West Virginia from Energy
Centre,  Inc.  a  corporation  owned  54.54%  by John Mork,  27.26% by Joseph E.
Casabona  and  9.10%  by  each  of  Donald C. Supcoe and J. Michael Forbes.  The
aggregate  amount  paid by the Company for rent to Energy Centre, Inc. was $0.56
million  for  fiscal year 2004.  The Company believes that such rental terms are
no  less  favorable  than  could  have been obtained from an unaffiliated party.

     ITEM  14.  PRINCIPAL  ACCOUNTING  FEES  AND  SERVICES

AUDIT  FEES

     The  aggregate  fees,  including  expenses,  Deloitte  &  Touche  LLP,  the
Company's principal accounting firm, billed the Company for each of the last two
fiscal years for professional services rendered in connection with the audits of
the  Company's  annual  financial statements and review of the Company quarterly
interim  financial statements were $326,182 for the year ended June 30, 2004 and
$416,318  for  the  year  ended  June  30,  2003.


                                       66
<PAGE>
AUDIT-RELATED  FEES

     Deloitte  &  Touche LLP did not bill the Company any additional fees in the
last  two  fiscal  years  for assurance and related services that are reasonably
related  to  the  performance  of the audit or review of the Company's Financial
Statements.

TAX  FEES

     The  aggregate  fees,  including expenses, Deloitte & Touche LLP billed the
Company  for  each  of  the  last  two  fiscal years for tax services related to
compliance,  advice,  or  planning was $458,241 for the year ended June 30, 2004
and  $678,365  for  the  year  ended  June  30,  2003.

ALL  OTHER  FEES

     Deloitte  &  Touche LLP did not bill the Company any additional fees in the
last  two  fiscal  years for products and services provided by Deloitte & Touche
LLP,  other  than  the  services  reported  above.

PRE-APPROVAL  POLICIES

     The  Company  does not have an audit committee or body performing a similar
function.  Pre-approval  of  all services performed by Deloitte & Touche LLP and
approval  of  the  related  fees is granted by a member or representative of the
Board  of  Directors  of  the  Company.


                                       67
<PAGE>
                                     PART IV
                                     -------

               ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES
               --------------------------------------------------
                            AND REPORTS ON FORM 8-K
                            ------------------------

<TABLE>
<CAPTION>
<S>  <C>  <C>  <C>    <C>
(a)    1              Financial Statements
                      The Financial Statements are filed as a part of this annual report at Item 8.

       2              Financial Statement Schedules
                      The Financial Statements are filed as a part of this annual report at Item 8.

       3              Exhibits
                      The following is a complete list of Exhibits filed as part of, or incorporated by
                      reference to this report:
            *    3.1  Articles of Incorporation of Energy Corporation of America.
            *    3.2  Amended Articles of Incorporation of Energy Corporation of America.
            *    3.3  Amended Bylaws of Energy Corporation of America.
            *    4.1  Intentionally omitted.
            *    4.2  Intentionally omitted.
            *    4.3  Indenture, dated as of May 23, 1997, between Energy Corporation of America
                      and The Bank of New York, as Trustee, with respect to the 9 1/2% Senior
                      Subordinated Notes Due 2007 (including form of 9 1/2% Senior Subordinated
                      Note Due 2007.
            *    4.4  Form of 9 1/2% Senior Subordinated Note due 2007, Series A.
            *    4.5  Registration Rights Agreement, dated as of May 20, 1997, among Energy
                      Corporation of America, as issuer, and Chase Securities Inc. and Prudential
                      Securities Inc.
            *   10.1  Eastern American Energy Corporation Profit/Incentive Stock Plan dated
                      as of June 4, 1997.
            *   10.2  Buy-Sell Stock Option Agreement dated as of May 19, 1997 among Energy
                      Corporation of America, F.H. McCullough, III and Kathy L. McCullough.
            *   10.3  Buy-Sell Stock Option Agreement dated as of July 8, 1996 between Energy
                      Corporation of America and Kenneth W. Brill.
            *   10.4  Gas Purchase Contract dated as of January 1, 1993 between Eastern
                      American Energy Corporation and Eastern Marketing Corporation.
            *   10.5  Intentionally omitted.
            *   10.6  Intentionally omitted.
            *   10.7  Intentionally omitted.


                                       68
<PAGE>
            *   10.8  Intentionally omitted.
            *   10.9  Intentionally omitted.
            *  10.10  Intentionally omitted.
            *  10.11  Intentionally omitted.
            *  10.12  Intentionally omitted.
            *  10.13  Intentionally omitted.
            *  10.14  Intentionally omitted.
            *  10.15  Intentionally omitted.
            *  10.16  Intentionally omitted.
            *  10.17  Incentive Stock Purchase Agreement dated February 12, 1999 by and
                      between Energy Corporation of America and Michael S. Fletcher.
            *  10.18  Incentive Stock Purchase Agreement dated December 16, 1998 by and
                      between Energy Corporation of America and Joseph E. Casabona.
            *  10.19  Incentive Stock Purchase Agreement dated December 16, 1998 by and
                      between Energy Corporation of America and Edward J. Davies.
           *   10.20  Incentive Stock Purchase Agreement dated December 16, 1998 by and
                      between Energy Corporation of America and Donald C. Supcoe.
            *  10.21  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                      between Energy Corporation of America and W. Gaston Caperton III.
            *  10.22  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                      between Energy Corporation of America and Peter H. Coors.
            *  10.23  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                      between Energy Corporation of America and L.B. Curtis.
            *  10.24  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                      between Energy Corporation of America and J. J. Dorgan.
            *  10.25  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                      between Energy Corporation of America and A. C. Nielsen, Jr.
            *  10.26  Stock Purchase Agreement dated February 17, 1999 by and among Westech
                      Energy Corporation, Westech Energy New Zealand Limited and Edward
                      J. Davies.
            *  10.27  Intentionally omitted.
            *  10.28  Intentionally omitted.
            *  10.29  Intentionally omitted.
            *  10.30  Intentionally omitted.
            *  10.31  Gas Sale and Purchase Agreement dated December 20, 1999 between Energy
                      Corporation of America and Allegheny Energy Service Corporation.
            *  10.32  Participation Agreement dated December 20, 1999 between Energy
                      Corporation of America and Allegheny Energy, Inc.


                                       69
<PAGE>
            *  10.33  Intentionally omitted.
            *  10.34  Intentionally omitted.
            *  10.35  Employment Agreement effective as of August 18, 2000 by and between
                      Energy Corporation of America and Michael S. Fletcher.
            *  10.36  Employment Agreement effective as of August 18, 2000 by and between
                      Energy Corporation of America and Donald C. Supcoe.
            *  10.37  Purchase and Sale Agreement dated June 28, 2001 between Tavener E&P Ltd
                      and Westech Energy Corporation.
            *  10.38  Credit Agreement dated July 10, 2002 between Energy Corporation of America
                      and Foothill Capital Corporation, as the Arranger and Administrative Agent
                      for the Lenders.
            *  10.39  Purchase and Sale Agreement dated August 2, 2002 between East Resources,
                      Inc. and Energy Corporation of America, without exhibits thereto.
            *  10.40  Amendment, effective as of June 29, 1997, to Buy-Sell Stock Option
                      Agreement between Energy Corporation of America and Kenneth W. Brill.
            *  10.41  Agreement dated December 28, 1998 between Energy Corporation of
                      America and Kenneth W. Brill.
                21.1  Subsidiaries of Energy Corporation of America.
                24.1  Power of Attorney set forth on the signature page contained in Part V.
                31.1  Certification of Chief Executive Officer Pursuant to Section 302 of the
                      Sarbanes-Oxley Act of 2002
                31.2  Certification of Chief Financial Officer Pursuant to Section 302 of the
                      Sarbanes-Oxley Act of 2002
            *   99.1  Order of the United States District Court for the Southern District of West
                      Virginia entered January 25, 2002 in civil action number 3:01-1317.
            *   99.2  Order of the United States District Court for the Southern District of West
                      Virginia entered June 3, 2002 in civil action number 3:01-1317.
            *   99.3  Order of the United States District Court for the Southern District of West
                      Virginia entered July 2002 in civil action number 3:01-1317.
            *   99.4  Unpublished opinion of the United States Court of Appeals for the
                      Fourth Circuit decided December 15, 2003 in appeal styled Energy Corporation
                      of America v. MacKay Shields LLC, et al.
            *   99.5  Stipulation and Final Judgement dated December 3, 2002 in the case styled
                      Energy Corporation of America v. MacKay Shields LLC, et al.
            *   99.6  Order of the United States District for the Southern District of West Virginia
                      entered December 4, 2003 in the above styled case.
            *   99.7  January 9, 2004, order of the United States Court of Appeals for the Fourth
                      Circuit in appeal styled Energy Corporation of America v. MacKay Shield
                      LLC, et al.


                                       70
<PAGE>
            *   99.8  Notice of Default from Wells Fargo Foothill, Inc. received January 23, 2004
            *   99.9  Forbearance Agreement entered into January 23, 2004 between the Company
                      and Wells Fargo Foothill, Inc.
            *  99.10  Intentionally omitted.
            *  99.11  Settlement Agreement among the Company and Noteholders.
            *  99.12  Energy Corporation of America commences asset sale offer to purchase up to
                      $4,000,000 aggregate principal amount of its 9 1/2% Senior Subordinated
                      Notes due 2007.
            *  99.13  Energy Corporation of America commences asset sale offer to purchase up to
                      $34,000,000 aggregate principal amount of its 9 1/2% Senior Subordinated
                      Notes due 2007.

       *  Previously filed

b)  Reports on Form 8-K:
</TABLE>

     The  Company  filed  a  report  on  Form 8-K, Item 5, dated June 15, 2004,
reporting  that the Company and Wells Fargo Foothill, Inc., have entered into an
amended  and  restated  credit  agreement  dated  June  10,  2004.

     The  Company  filed  a  report  on  Form  8-K, Item 5, dated June 30, 2004,
announcing the commencement of an asset sale offer for the purchase of up to $34
million  aggregate  principal  amount  of its 9 1/2 % Senior Subordinated Notes.

                                  * * * * * *


                                       71
<PAGE>
                                     PART V
                                     -------


SIGNATURES

Pursuant  to  the requirements of Section 13 or 15(d) of the Securities Exchange
Act  of  1934,  the  registrant  has duly caused this report to be signed on its
behalf  by  the  undersigned  thereunto,  duly  authorized,  on  the 27th day of
September  2004.

                                     ENERGY  CORPORATION  OF  AMERICA

                                     By:  /s/ John Mork
                                          --------------------------------------
                                          John  Mork
                                          President and Chief Executive Officer


                                       72
<PAGE>
                                POWER OF ATTORNEY
                                -----------------

     Each  of  the  undersigned  officers and directors of Energy Corporation of
America  (the  "Company")  hereby  constitutes and appoints John Mork, Joseph E.
Casabona  and  Michael  S. Fletcher and each of them (with full power to each of
them  to  act  alone), his true and lawful attorney-in-fact and agent, with full
power  of  substitution,  for  him  and on his behalf and in his name, place and
stead, in any and all capacities, to sign, execute and file this Form 10-K under
the  Securities  Act  of 1934, as amended, and any or all amendments (including,
without  limitation,  post-effective  amendments), with all exhibits and any and
all documents required to be filed with respect thereto, with the Securities and
Exchange  Commission  or  any  regulatory  authority,  granting  unto  such
attorneys-in-fact  and  agents,  and  each  of them acting alone, full power and
authority  to do and perform each of every act and thing requisite and necessary
to be done in and about the premises in order to effectuate the same, as full to
all  intents and purposes as he himself might or could do if personally present,
hereby  ratifying  and  confirming all the such attorneys-in-fact and agents, or
any  of them, or their substitute or substitutes, may lawfully do or cause to be
done.

     Pursuant  to the requirements of the Securities Act of 1934, this Form 10-K
has  been  signed on the 27th day of September 2004, by the following persons in
the  capacities  indicated.


                                       73
<PAGE>
<TABLE>
<CAPTION>
        Signature                                Title
--------------------------  ------------------------------------------------
<S>                         <C>

/s/ John Mork
--------------------------
John Mork                   President, Chief Executive Officer and Director
                            (Principal executive officer)

/s/ Joseph E. Casabona
--------------------------
Joseph E. Casabona          Executive Vice President and Director

/s/ Michael S. Fletcher
--------------------------
Michael S. Fletcher         Chief Financial Officer
                            (Principal accounting and financial officer)

/s/ F. H. McCullough III
--------------------------
F. H. McCullough III        Director

/s/ Gaston Caperton
--------------------------
Gaston Caperton             Director

/s/ Peter H. Coors
--------------------------
Peter H. Coors              Director

/s/ L. B. Curtis
--------------------------
L. B. Curtis                Director

/s/ John J. Dorgan
--------------------------
John J. Dorgan              Director

/s/ Julie Mork
--------------------------
Julie Mork                  Director

/s/ Arthur C. Nielsen, Jr.
--------------------------
Arthur C. Nielsen, Jr.      Director

/s/ Jay S. Pifer
--------------------------
Jay S. Pifer                Director
</TABLE>


                                       74
<PAGE>